U.S. patent application number 12/151505 was filed with the patent office on 2009-11-12 for methods of using a lower-quality water for use as some of the water in the forming and delivering of a treatment fluid into a wellbore.
Invention is credited to Jason Bryant, Shaun Bums, Leonard Case, Herbert Hornick, Von Parkey, Michael Segura, Billy Francis Slabaugh, JR., Tommy Slabaugh, Jonn Thompson, Harold Walters.
Application Number | 20090277641 12/151505 |
Document ID | / |
Family ID | 41265940 |
Filed Date | 2009-11-12 |
United States Patent
Application |
20090277641 |
Kind Code |
A1 |
Walters; Harold ; et
al. |
November 12, 2009 |
Methods of using a lower-quality water for use as some of the water
in the forming and delivering of a treatment fluid into a
wellbore
Abstract
The inventions are for methods of forming and delivering a
treatment fluid into a wellbore. In one aspect, methods are
provided of treating a base aqueous solution to obtain a first
aqueous solution, for example, to have a substantially reduced
concentration of at least one component relative to the
concentration of the component in the base aqueous solution, and
using the first aqueous solution and a lower-quality water, such as
the base aqueous solution, to form a treatment fluid. The first
aqueous solution and the lower-quality water are merged after
pumping the fluid portions toward the wellbore. The component is
selected for being deleterious to the use or performance of a
treatment fluid. More particularly, the component is selected from
the group consisting of: a dissolved ion, oil, grease, a production
chemical, and suspended, water-insoluble solids. This allows the
use of lower-quality water for some of the water required for
making up the treatment fluid.
Inventors: |
Walters; Harold; (Duncan,
OK) ; Bryant; Jason; (Duncan, OK) ; Case;
Leonard; (Duncan, OK) ; Thompson; Jonn;
(Flint, TX) ; Segura; Michael; (Duncan, OK)
; Hornick; Herbert; (Duncan, OK) ; Parkey;
Von; (Oklahoma City, OK) ; Bums; Shaun; (Grand
Junction, CO) ; Slabaugh, JR.; Billy Francis;
(Wichita Falls, TX) ; Slabaugh; Tommy; (Wichita
Falls, TX) |
Correspondence
Address: |
ROBERT A. KENT
P.O. BOX 1431
DUNCAN
OK
73536
US
|
Family ID: |
41265940 |
Appl. No.: |
12/151505 |
Filed: |
May 7, 2008 |
Current U.S.
Class: |
166/305.1 |
Current CPC
Class: |
C09K 8/685 20130101;
E21B 43/267 20130101; C09K 8/68 20130101; E21B 21/062 20130101;
C09K 2208/08 20130101 |
Class at
Publication: |
166/305.1 |
International
Class: |
E21B 43/22 20060101
E21B043/22 |
Claims
1. A method of forming and delivering a treatment fluid into a
wellbore, the method comprising the steps of continuously: (a)
pumping a first fluid comprising a first aqueous solution; (b)
pumping a second fluid comprising a second aqueous solution; (c)
merging at least the first and second fluids to form a treatment
fluid comprising a merged aqueous solution, wherein the merged
aqueous solution comprises at least 25% by weight of the first
aqueous solution and at least 25% by weight of the second aqueous
solution, and wherein the merged aqueous solution has a merged
viscosity of less than 100 cP at 40 1/s and at 25.degree. C.
(77.degree. F.), and wherein the step of merging is after the steps
of pumping the first and second fluids; and then (d) directing the
treatment fluid into the wellbore; wherein: (i) the merged aqueous
solution has a merged concentration of at least one component
selected from the group consisting of: a dissolved ion, oil,
grease, a production chemical, and suspended solids; (ii) the first
aqueous solution has a concentration of the at least one component
that is substantially lower than the merged concentration of the at
least one component; (iii) the second aqueous solution has a
concentration of the at least one component that is substantially
higher than the merged concentration of the at least one component;
and (iv) the first, second, and treatment fluids are handled as
fluid streams.
2. The method according to claim 1, wherein the first fluid
comprises a first concentration of a hydratable additive and the
second fluid has a second concentration of the hydratable additive
that is substantially lower than the first concentration of the
hydratable additive.
3. The method according to claim 1, wherein the merged aqueous
solution has a merged viscosity of less than 35 cP.
4. The method according to claim 1, wherein the component is at
least one dissolved ion.
5. The method according to claim 4, further comprising a step of
treating a base aqueous solution to obtain the first aqueous
solution having a substantially reduced concentration of the at
least one ion relative to the concentration of the at least one ion
in the base aqueous solution.
6. The method according to claim 5, wherein the step of treating
comprises selectively reducing the concentration of the at least
one dissolved ion.
7. The method according to claim 4, wherein the at least one ion is
selected from the group consisting of calcium, magnesium, sulfate,
iron, and borate.
8. The method according to claim 7, wherein the second aqueous
solution has a substantial concentration of sulfate ions of equal
to or greater than 500 ppm; a substantial concentration of calcium
or magnesium ions of equal to or greater than a combined total of
1,000 ppm; a substantial concentration of iron ions of equal to or
greater than 10 ppm; or a substantial concentration of borate ions
of equal to or greater than 5 ppm.
9. The method according to claim 1, further comprising a step of
forming the first fluid comprising: (i) an unhydrated hydratable
additive; and (ii) the first aqueous solution.
10. The method according to claim 9, further comprising a step of
allowing the hydratable additive in the first fluid to reach at
least 50% hydration prior to the step of pumping the first
fluid.
11. The method according to claim 1, wherein: (i) the treatment
fluid comprises a merged concentration of a particulate; (ii) the
first fluid comprises a first concentration of the particulate that
is substantially higher than the merged concentration of the
particulate; (iii) the second fluid comprises a second
concentration of the particulate that is substantially lower than
the merged concentration of the particulate; and (iv) the first
fluid is pumped at a substantially lower average bulk fluid
velocity than the second fluid.
12. The method according to claim 1, wherein: (i) the treatment
fluid comprises a merged concentration of a particulate and a
merged concentration of the hydratable additive; (ii) the first
fluid comprises a first concentration of the particulate that is
substantially higher than the merged concentration of the
particulate and a first concentration of the additive that is
substantially higher than the merged concentration of the additive;
(iii) the second fluid comprises a second concentration of the
particulate that is substantially lower than the merged
concentration of the particulate and a second concentration of the
additive that is substantially lower than the merged concentration
of the additive.
13. A method of forming and delivering a treatment fluid into a
wellbore, the method comprising the steps of continuously: (a)
pumping a first fluid comprising a first aqueous solution; (b)
pumping a second fluid comprising a second aqueous solution; (c)
merging at least the first and second fluids to form a treatment
fluid comprising a merged aqueous solution, wherein the merged
aqueous solution comprises at least 25% by weight of the first
aqueous solution and at least 25% by weight of the second aqueous
solution, and wherein the merged aqueous solution has a merged
viscosity of less than 100 cP at 40 1/s and at 25.degree. C.
(77.degree. F.), and wherein the step of merging is after the steps
of pumping the first and second fluids; and then (d) directing the
treatment fluid into a wellbore; wherein: (i) the merged aqueous
solution has a merged concentration of total dissolved solids; (ii)
the first aqueous solution has a concentration of total dissolved
solids that is substantially lower than the merged concentration of
total dissolved solids; (iii) the second aqueous solution has a
concentration of total dissolved solids that is substantially
higher than the merged concentration of total dissolved solids; and
(iv) the first, second, and treatment fluids are handled as fluid
streams.
14. The method according to claim 13, wherein the first fluid
comprises a first concentration of a hydratable additive and the
second fluid has a second concentration of the hydratable additive
that is substantially lower than the first concentration of the
hydratable additive.
15. The method according to claim 13, wherein the merged aqueous
solution has a merged viscosity of less than 35 cP.
16. The method according to claim 13, further comprising a step of
treating a base aqueous solution to obtain the first aqueous
solution having a substantially reduced concentration of total
dissolved solids relative to the concentration of total dissolved
solids in the base aqueous solution.
17. The method according to claim 16, wherein the base aqueous
solution is selected for having a concentration of total dissolved
solids of greater than 40,000 ppm.
18. The method according to claim 17, wherein the first aqueous
solution is treated at least sufficiently to have a concentration
of total dissolved solids of less than 30,000 ppm.
19. The method according to claim 17, wherein the second aqueous
solution is selected for having a concentration of total dissolved
solids of greater than 40,000 ppm.
20. The method according to claim 16, wherein the base aqueous
solution is selected to be the same as the second aqueous
solution.
21. The method according to claim 1, wherein the wellbore
penetrates an oil or gas reservoir.
22. The method according to claim 13, wherein the wellbore
penetrates an oil or gas reservoir.
23. The method according to claim 1, wherein the first fluid is
pumped with a first positive-displacement pump, and the second
fluid is pumped with a second positive-displacement pump.
24. The method according to claim 13, wherein the first fluid is
pumped with a first positive-displacement pump, and the second
fluid is pumped with a second positive-displacement pump.
Description
CROSS-REFERENCE TO RELATED APPLICATIONS
[0001] Not applicable
STATEMENT REGARDING FEDERALLY SPONSORED RESEARCH OR DEVELOPMENT
[0002] Not applicable
REFERENCE TO MICROFICHE APPENDIX
[0003] Not applicable
BRIEF SUMMARY OF THE INVENTION
[0004] In general, the inventions relate to methods of forming and
delivering a treatment fluid into a wellbore. As used herein,
"forming" a fluid includes mixing or merging two or more fluids or
a fluid with a powdered or particulate material, such as a powdered
dissolvable or hydratable additive (prior to hydration) or a
proppant. In a continuous treatment or in a continuous part of a
well treatment, the fluids are handled as fluid streams.
[0005] As used herein, "delivering" into a wellbore includes
pumping and directing the treatment fluid into a wellbore. The step
of pumping can be on the separate fluid streams used to make up the
treatment fluid, on merged streams, or on the completely formed
treatment fluid, depending on the method according to the
inventions. The step of directing the treatment fluid into a
wellbore can be on the separate fluid streams, on a merged fluid
stream, or on the completely formed treatment fluid. The merging of
separate fluid streams may take place, for example, as the separate
fluid streams are directed toward the wellbore, as they enter into
the wellbore, or as they move through the wellbore. Directing a
fluid stream is typically accomplished with piping or other
tubulars. Separate streams of pumped fluid can be merged by using,
for example, one or more manifolds.
Using Lower-Quality Water for a Portion of the Treatment Fluid
[0006] The first aspect of the inventions generally relates using
higher-quality water for one portion of the water for a treatment
fluid and lower-quality water for another portion of the water for
a treatment fluid, and merging the two portions to form the
treatment fluid after pumping the fluid portions toward the
wellbore. According this first aspect, a method is provided
comprising the steps of continuously: (a) pumping a first fluid
comprising a first aqueous solution; (b) pumping a second fluid
comprising a second aqueous solution; (c) merging at least the
first and second fluids to form a treatment fluid comprising a
merged aqueous solution, wherein the merged aqueous solution
comprises at least 25% by weight of the first aqueous solution and
at least 25% by weight of the second aqueous solution, and wherein
the merged aqueous solution has a merged viscosity of less than 100
cP at 40 l/s and at 25.degree. C. (77.degree. F.); and (d)
directing the treatment fluid into the wellbore. In general, the
second aqueous solution is lower-quality water relative to the
first aqueous solution in any material respect relevant to the
purpose of forming the treatment fluid or using the treatment
fluid. For example, a material respect for the purpose of forming a
treatment fluid may be the concentration of a certain dissolved
ion, and lower-quality water in such a respect has a higher
concentration of such ion.
[0007] According to one embodiment of this first aspect of the
inventions: (i) the merged aqueous solution has a merged
concentration of at least one component selected from the group
consisting of: a dissolved ion, oil, grease, a production chemical,
and suspended solids; (ii) the first aqueous solution has a
concentration of the at least component that is substantially lower
than the merged concentration of the at least one component; and
(iii) the second aqueous solution has a concentration of the at
least one component that is substantially higher than the merged
concentration of the at least one component. This allows the use of
lower-quality water for some of the water required for making up
the treatment fluid. The component is selected for being
deleterious to the use or performance of a treatment fluid.
[0008] According to another embodiment of this first aspect of the
inventions: (i) the merged aqueous solution has a merged
concentration of total dissolved solids; (ii) the first aqueous
solution has a concentration of total dissolved solids that is
substantially lower than the merged concentration of total
dissolved solids; and (iii) the second aqueous solution has a
concentration of total dissolved solids that is substantially
higher than the merged concentration of total dissolved solids.
Treating Lower-Quality Water for Use as a Portion of a Treatment
Fluid
[0009] A second aspect of the inventions generally relates to
treating a base aqueous solution to obtain a first aqueous
solution, for example, to have a substantially reduced
concentration of at least one component relative to the
concentration of the at least one component in the base aqueous
solution, and using the first aqueous solution and a lower-quality
water, such as the base aqueous solution, to form a treatment
fluid. More particularly, the component is selected from the group
consisting of: a dissolved ion, oil, grease, a production chemical,
and suspended solids. This allows the use of lower-quality water
for some of the water required for making up the treatment fluid.
The first aqueous solution and the lower-quality water are merged
after pumping the fluid portions toward the wellbore. The component
is selected for being deleterious to the use or performance of a
treatment fluid.
[0010] According to one embodiment of this second aspect of the
inventions, a method of forming and delivering a treatment fluid
into a wellbore is provided, the method comprising the steps of:
(a) treating a base aqueous solution to obtain the first aqueous
solution having a substantially reduced concentration of at least
one component relative to the concentration of the at least one
component in the base aqueous solution, wherein the component is
selected from the group consisting of: a dissolved ion, oil,
grease, a production chemical, and suspended solids; (b) pumping a
first fluid comprising the first aqueous solution; (c) pumping a
second fluid comprising a second aqueous solution; (d) merging at
least the first and second fluids to form a treatment fluid
comprising a merged aqueous solution, wherein the merged aqueous
solution comprises at least 25% by weight of the first aqueous
solution and at least 25% by weight of the second aqueous solution,
and wherein the merged aqueous solution has a merged viscosity of
less than 100 cP at 40 l/s and at 25.degree. C. (77.degree. F.);
and (e) directing the treatment fluid into the wellbore. More
particularly, (i) the merged aqueous solution has a merged
concentration of the at least one component; (ii) the first aqueous
solution has a concentration of the at least one component that is
substantially lower than the merged concentration of the at least
one component; and (iii) the second aqueous solution has a
concentration of the at least one component that is substantially
higher than the merged concentration of the at least one
component.
[0011] According to another embodiment of this second aspect of the
inventions, a method of forming and delivering a treatment fluid
into a wellbore is provided, the method comprising the steps of:
(a) treating a base aqueous solution to obtain the first aqueous
solution having a substantially reduced concentration of total
dissolved solids relative to the concentration of the total
dissolved solids in the base aqueous solution; (b) pumping a first
fluid comprising the first aqueous solution; (c) pumping a second
fluid comprising a second aqueous solution; (d) merging at least
the first and second fluids to form a treatment fluid having a
merged aqueous solution, wherein the merged aqueous solution
comprises at least 25% by weight of the first aqueous solution and
at least 25% by weight of the second aqueous solution, and wherein
the merged aqueous solution has a merged viscosity of less than 100
cP at 40 l/s and at 25.degree. C. (77.degree. F.); and (e)
directing the treatment fluid into a wellbore. More particularly,
(i) the merged aqueous solution has a merged concentration of total
dissolved solids; (ii) the first aqueous solution has a
concentration of total dissolved solids that is substantially lower
than the merged concentration of total dissolved solids; and (iii)
the second aqueous solution has a concentration of total dissolved
solids that is substantially higher than the merged concentration
of total dissolved solids.
Prehydrating an Unhydrated Hydratable Additive
[0012] The third aspect of the inventions generally relates to
prehydrating an unhydrated hydratable additive in water having a
lower concentration of at least one ion that can interfere with the
hydration or cross-linking of the hydratable additive and then
mixing the prehydrated additive with water having a higher
concentration of such ion. According to this third aspect, the
method comprises the steps of: (a) forming a premix fluid
comprising: (i) an unhydrated hydratable additive; and (ii) a first
aqueous solution; (b) subsequently forming a treatment fluid
comprising: (i) the premix fluid; and (ii) a second aqueous
solution; and (c) simultaneously with or subsequently to the step
of forming the treatment fluid, delivering the treatment fluid into
the wellbore. As used herein, it should be understood that a lower
concentration of any material, such as a certain type of dissolved
ion, may mean and include a zero concentration of such
material.
[0013] According to one embodiment of this third aspect of the
inventions: (i) the first aqueous solution has a concentration of
at least one ion that is substantially lower than the concentration
of the at least one ion in the second aqueous solution; and (ii)
the treatment fluid has a merged viscosity of less than 100 cP at
40 l/s and at 25.degree. C. (77.degree. F.).
[0014] According to another embodiment of this third aspect of the
inventions: (i) the first aqueous solution has combined dissolved
calcium and magnesium ions of less than 10,000 ppm; and (ii) the
second aqueous solution has combined dissolved calcium and
magnesium ions of greater than 15,000 ppm; and (iii) the treatment
fluid has a merged viscosity of less than 100 cP at 40 l/s and at
25.degree. C. (77.degree. F.).
[0015] According to yet another embodiment of this third aspect,
(i) the first aqueous solution has total dissolved solids of less
than 30,000 ppm; and (ii) the second aqueous solution has total
dissolved solids of greater than 40,000 ppm; and (iii) the
treatment fluid has a merged viscosity of less than 100 cP at 40
l/s and at 25.degree. C. (77.degree. F.).
Pumping Different Particulate Concentrations at Different Average
Bulk Fluid Velocities
[0016] The fourth aspect of the inventions generally relates to
pumping a first fluid having a relatively high concentration of a
particulate suspended therein and pumping a second fluid having
either none of the particulate or a relatively low concentration of
the particulate suspended therein, and then merging at least the
first and second fluids to form a treatment fluid having a merged
concentration of the particulate. According to this aspect, the
first and second fluids are pumped at different average bulk fluid
velocities. In this context, "particulate" means and refers to a
solid, water-insoluble material having consistently defined
characteristics, such as material and mesh size. An example of a
particulate includes, for example, 20-40 mesh sand for use as
proppant.
[0017] According to this fourth aspect, the method comprises the
steps of: (a) pumping a first fluid comprising a first aqueous
solution with a first positive-displacement pump; (b) pumping a
second fluid comprising a second aqueous solution with a second
positive-displacement pump; (c) merging at least the first and
second fluids to form a treatment fluid; and (d) directing the
treatment fluid into a wellbore. For this aspect of the inventions:
(i) the treatment fluid comprises a merged concentration of the
particulate; (ii) the first fluid comprises a first concentration
of the particulate that is substantially higher than the merged
concentration of the particulate; (iii) the second fluid comprises
a second concentration of the particulate that is substantially
lower than the merged concentration of the particulate; and (iv)
the first fluid is pumped at a substantially lower average bulk
fluid velocity than the average bulk fluid velocity at which the
second fluid is pumped. As used herein, it should be understood
that a relatively low concentration of any material, such as a
proppant, may mean and include a zero concentration of such
material.
[0018] According to this aspect of the inventions, preferably the
first fluid and the second fluid each comprise at least 10% by
weight of the treatment fluid. More preferably according to this
aspect, the first fluid and the second fluid each comprise at least
25% by weight of the treatment fluid.
Pumping Fluids with Different Concentrations of Particulate and
Hydratable Additive
[0019] The fifth aspect of the inventions generally relates to
pumping a first fluid having a relatively high concentration of a
particulate suspended therein and pumping a second fluid having
either none of the particulate or a relatively low concentration of
the particulate suspended therein, and then merging at least the
first and second fluids to form a treatment fluid having a merged
concentration of the particulate. According to this aspect, the
first fluid also has a relatively high concentration of a
hydratable additive and the second fluid has either none or a
relatively low concentration of the additive. In this context, the
particulate means and refers to a solid, insoluble material having
consistently defined characteristics, such as mesh size. An example
of a particulate includes, for example, 20-40 mesh sand for use as
proppant. The hydratable additive is preferably selected from the
group consisting of a water-soluble viscosity-increasing agent, a
water-soluble a friction-reducing agent, or a water-soluble
elasticity-increasing agent.
[0020] According to this fifth aspect, the method comprises the
steps of: (a) pumping a first fluid comprising a first aqueous
solution with a first positive-displacement pump; (b) pumping a
second fluid comprising a second aqueous solution with a second
positive-displacement pump; (c) merging at least the first and
second fluids to form a treatment fluid; and (d) directing the
treatment fluid into a wellbore. For this aspect of the inventions:
(i) the treatment fluid comprises a merged concentration of a
particulate and a merged concentration of a hydratable additive,
where the additive is a water-soluble viscosity-increasing agent, a
water-soluble friction-reducing agent, or a water-soluble
elasticity-increasing agent; (ii) the first fluid comprises a first
concentration of the particulate that is substantially higher than
the merged concentration of the particulate and a first
concentration of the additive that is substantially higher than the
merged concentration of the additive; and (iii) the second fluid
comprises a second concentration of the particulate that is
substantially lower than the merged concentration of the
particulate and a second concentration of the additive that is
substantially lower than the merged concentration of the
additive.
[0021] As used herein, the words "comprise," "has," and "include"
and all grammatical variations thereof are each intended to have an
open, non-limiting meaning that does not exclude additional steps,
elements, ingredients, or materials. Further, as used herein, the
term "substantially" in regard to a relative difference means a
difference of at least 25%. For example, if a first concentration
of a particular ion or of proppant is substantially lower than a
second concentration, it means that the first concentration is at
least 25% lower than the second concentration, down to and
including a first concentration of zero. If the difference is not
expressly stated with respect to another concentration, then the
difference is based on the larger of the two measurements.
[0022] As used herein, "base," "first," "second," "premix," and
"merged" may be arbitrarily assigned and are merely intended to
differentiate between two or more fluids, aqueous solutions,
concentrations, viscosities, pumps, etc., as the case may be.
Furthermore, it is to be understood that the mere use of the term
"first" does not require that there be any "second," and the mere
use of the word "second" does not require that there by any
"third," etc.
[0023] Preferably, two or more aspects of the invention or
preferred embodiments are used together or in subcombination to
obtain combined methods and synergistic benefits, advantages, and
costs savings.
[0024] These and further aspects and embodiments of the inventions
and various advantages of the aspects and embodiments of the
inventions are in the detailed description.
BRIEF DESCRIPTION OF THE DRAWING
[0025] A more complete understanding of the present inventions and
the advantages thereof may be acquired by referring to the
following description taken in conjunction with the accompanying
drawings in which:
[0026] FIG. 1 is a flow diagram of a conventional equipment spread
used in hydraulic fracturing of a portion of a reservoir adjacent a
wellbore penetrating the reservoir. A typical fracturing uses water
that is entirely made up of potable water, freshwater, and/or
treated water. The water is mixed with a viscosity-increasing agent
in an "ADP" or "GEL PRO" mixer or mixing step to provide a higher
viscosity fluid to help suspend sand or other particulate. The
water and/or the higher-viscosity water-based fluid are then mixed
with sand in a blender to form a treatment fluid for fracturing. An
array of high-pressure ("HP") pumps that are arranged in parallel
is used to deliver the treatment fluid into the wellbore of a
well.
[0027] FIG. 2 is a flow diagram of an example of the equipment
spread that may be used in various methods according to the
inventions. Fluid stream 1 is comprised of, for example, potable
water, freshwater, treated water, or any combination thereof, such
that it has, for example, relatively low total dissolved solids.
The treated water for use in Fluid stream 1 may have been subjected
to water treatments such as filtration to remove undissolved
solids, removal of certain dissolved ions, pH adjustment, and
bacterial treatment. Fluid stream 2 is comprised of, for example,
untreated produced, returned water, brine, or any combination
thereof such that it has, for example, relatively high total
dissolved solids. A low pressure pump, e.g., a centrifugal pump,
may be used to transport the water for fluid stream 2 to the HP
pumps. The relatively clean water is mixed with a
viscosity-increasing agent to provide a higher viscosity fluid to
help suspend sand or other particulate. The relatively clean water
and/or the higher-viscosity fluid are then mixed with sand in a
blender. An array of HP pumps that are arranged in parallel is used
to pump fluid stream 1 and fluid stream 2, after which the fluid
streams are merged to form a treatment fluid and directed into the
wellbore of a well. Chemicals, such as viscosity-increasing agent
or fluid friction-reducing agent, and other materials, such as
sand, may be partitioned via a partitioning manifold between the
fluid stream 1 and fluid stream 2. According to one of the aspects
of the inventions, the pumps may be operated to pump fluid stream 1
and fluid stream 2 at different average bulk fluid velocities based
on different concentrations of particulate in the fluid streams to
reduce pump wear and maintenance.
[0028] FIG. 3 is a flow diagram similar to the flow diagram of FIG.
2 with the addition of an optional step of water-treatment
operations in fluid stream 2. The water-treatment operations may
be, for example, for the removal of one or more undesirable
components. Water treatments may include filtration to remove
undissolved solids, removal of certain dissolved ions, pH
adjustment, and bacterial treatment. The water treatments used to
obtain treated water for use in fluid stream 1 are expected to be
different than those used in fluid stream 2.
[0029] FIG. 4 is a graphical representation of the erosion wear for
pumps used in pumping either fluid with proppant or without
proppant. This data was collected during actual water-frac
stimulation treatments done over a 3-month time frame. During the
test period, a total of 9.5 million pounds of proppant were pumped
in 4.93 million gallons of fluid in a total of 148 treating
applications.
DETAILED DESCRIPTION OF THE INVENTION
[0030] Oil and gas hydrocarbons are naturally occurring in some
subterranean formations, which are called reservoirs. As used
herein, a well includes at least one wellbore drilled into the
earth to try and reach an oil or gas reservoir and produce oil or
gas from the reservoir.
[0031] As used herein, the term "wellbore" refers to the wellbore
itself, including the openhole or uncased portion of the well.
Further, as used herein, "into the wellbore" means and includes
directly into and through the wellbore or into and through a
casing, liner, or other tubular within the wellbore. The
near-wellbore region is the subterranean material and rock of the
subterranean formation surrounding the wellbore.
[0032] It is often desirable to treat a wellbore or a portion of a
subterranean formation with various types of treatment fluids in
the efforts to produce oil or gas from a reservoir. A treatment is
designed to resolve a specific wellbore or reservoir condition. For
example, stimulation is a treatment performed on a well to restore
or enhance the productivity of the well. Stimulation treatments
fall into two main groups, hydraulic fracturing and matrix
treatments. Fracturing treatments are performed above the fracture
pressure of the reservoir formation and create a highly conductive
flow path between the reservoir and the wellbore. Hydraulic
fracturing will hereinafter be described in more detail. Matrix
treatments are performed below the reservoir fracture pressure and
generally are designed to restore the natural permeability of the
reservoir following damage to the near-wellbore region.
[0033] As used herein, a "treatment fluid" is a fluid designed and
prepared to resolve a specific wellbore or reservoir condition. The
treatment fluid may be for any of a wide variety of downhole
purposes in a well, such as stimulation, isolation, or control of
reservoir gas or water. "Stimulation" is a treatment for the
purpose of enhancing or stimulating oil or gas production.
"Isolation" is a treatment for the purpose of isolating one region
or portion of a wellbore or subterranean formation from another.
"Control" is a treatment for the purpose of controlling or limiting
excess water production or sand production from the well. Treatment
fluids are typically prepared adjacent to the wellhead at the well
site. The term "treatment" in the term "treatment fluid" does not
necessarily imply any particular action by the fluid. As used
herein, a fluid may or may not be a slurry, which is a suspension
of insoluble particles (such as sand, clay, etc.) in a fluid. The
treatment fluids are often, but not necessarily, water based. It
should be understood from the context of these inventions, of
course, that as used herein a "fluid" is a continuous amorphous
substance that tends to flow and to conform to the outline of its
container as a liquid or a gas, when tested at a temperature at
room temperature of 68.degree. F. (20.degree. C.) and standard
pressure (1 atm).
[0034] As used herein, "water-based" means that the fluid comprises
greater than 50% by weight of an aqueous solution. In general, as
used herein, an "aqueous solution" refers to a water used or
received to be used in any of the methods according to the
invention. The water is referred to as an "aqueous solution"
because it would be expected to normally include substantial or
insubstantial concentrations of dissolved solids, such as sodium
chloride, calcium chloride, magnesium chloride, sodium sulfate, and
other water-soluble salts (up to the saturation limit of each). The
term "aqueous solution" may include small amounts of other
materials, however, the term excludes anything that is included in
or added to the aqueous solution for the purposes of a well
treatment in which the aqueous solution is to be used. For example
and preferably, an "aqueous solution" may be up to 1% by weight of
total water-miscible or water-soluble organic materials; up to 2%
by weight of total dispersed, oil, grease, and water-insoluble
production chemicals; up to 10% by weight of total dispersed oil,
grease, and non-surfactant water-insoluble production chemicals
with surfactant production chemicals; and up to 1% by weight of
total suspended silt or smaller particles (avoiding any layer of
oil or other insoluble materials floating on the surface or any
sludge settled on the bottom of the water as received). For
example, the oil, grease, and production chemicals would be
typically found, for example, in produced water. A water-based
fluid (comprising an aqueous solution) may or may not include other
suspended components, such as oil, clay, proppant, and other
additives, which can be added to or mixed with the aqueous solution
for the purposes of forming a treatment fluid for a well treatment.
A water-based fluid can be an emulsion, foamed with a gas, or both.
For example, such suspended components can be selected from the
group consisting of: a clay, a water-insoluble organic material, a
gas, and any combination thereof in any proportion. Further, a
water-based fluid may include other water-soluble or water-miscible
additives.
[0035] An example of a water-based treatment fluid is a fracturing
fluid. Another example of a water-based treatment fluid is a
drilling mud, which includes an aqueous solution and undissolved
solids (as solid suspensions, mixtures, and emulsions). A
water-based drilling mud can be based on a brine. Both the
dissolved solids and the undissolved solids can be chosen to help
increase the density of the fluid. A commonly-used example of an
undissolved weighting agent is bentonite clay. The density of a
drilling mud can be much higher than that of typical seawater or
even higher than high-density brines due to the presence of
suspended solids.
[0036] As will hereinafter be explained in more detail, the methods
of the present inventions are most particularly directed to and
preferably used in the formation and delivery of a treatment fluid
that is used in a high volume in a well treatment, i.e., greater
than 1,000 barrels (42,000 U.S. gallons). Further, it is to be
understood that a treatment fluid is preferably to be formed and
delivered continuously or "on the fly" into a wellbore. In
addition, it should be understood that a treatment fluid is formed
to have substantially the same composition in all material
respects, such as concentrations of the amount of hydratable
polymer and other components used, although the amount of proppant
concentration may be varied, for example, in the case of a
treatment fluid having a ramped up concentration of proppant or
having a higher "tail-end" concentration of a particulate (such as
a proppant). In a well treatment where the concentration of
particulate varies in the course of delivering a treatment fluid
into a wellbore for a particular treatment, as in the case of a
higher tail-end concentration of proppant in a water-frac, the
concentration of particulate in the treatment fluid or in a fluid
used to make up the treatment fluid is the average concentration
over the course of delivering the treatment fluid into the
wellbore. Except for variations in the concentration of the
particulate, substantial variations in the concentrations of the
various materials or components of specified herein to be required
in a treatment fluid would be defined as a separate or different
treatment fluid. Of course, variations in composition that do not
otherwise materially impact the usefulness or the performance of
the treatment fluid are permissible.
Hydraulic Fracturing and Proppant
[0037] "Hydraulic fracturing," sometimes simply referred to as
"fracturing," is a common stimulation treatment. A treatment fluid
for this purpose is sometimes referred to as a "fracturing fluid."
The fracturing fluid is pumped at a high flow rate and high
pressure down into the wellbore and out into the formation. The
pumping of the fracturing fluid is at a high flow rate and pressure
that is much faster and higher than the fluid can escape through
the permeability of the formation. Thus, the high flow rate and
pressure creates or enhances a fracture in the subterranean
formation. Creating a fracture means making a new fracture in the
formation. Enhancing a fracture means enlarging a pre-existing
fracture in the formation.
[0038] For pumping in hydraulic fracturing, a "frac pump" is used,
which is a high-pressure, high-volume pump. Typically, a frac pump
is a positive-displacement reciprocating pump. These pumps
generally are capable of pumping a wide range of fluid types,
including corrosive fluids, abrasive fluids and slurries containing
relatively large particulates, such as sand. Using a frac pump, the
fracturing fluid may be pumped down into the wellbore at high rates
and pressures, for example, at a flow rate in excess of 100 barrels
per minute (3,100 U.S. gallons per minute) at a pressure in excess
of 5,000 pounds per square inch ("psi"). The pump rate and pressure
of the fracturing fluid may be even higher, for example, pressures
in excess of 10,000 psi are not uncommon.
[0039] To fracture a subterranean formation typically requires
hundreds of thousands of gallons of fracturing fluid. Further, it
is often desirable to fracture at more than one downhole location.
For various reasons, including the high volumes of fracturing fluid
required, ready availability, and historically low cost, the
fracturing fluid is usually water or water-based. Thus, fracturing
a well may require millions of gallons of water.
[0040] When the formation fractures or an existing fracture is
enhanced, the fracturing fluid suddenly has a fluid flow path
through the crack to flow more rapidly away from the wellbore. As
soon as the fracture is created or enhanced, the sudden increase in
flow of fluid away from the well reduces the pressure in the well.
Thus, the creation or enhancement of a fracture in the formation is
indicated by a sudden drop in fluid pressure, which can be observed
at the well head.
[0041] After it is created, the newly-created fracture will tend to
close after the pumping of the fracturing fluid is stopped. To
prevent the fracture from closing, a material must be placed in the
fracture to keep the fracture propped open. This material is
usually in the form of an insoluble particulate, which can be
suspended in the fracturing fluid, carried downhole, and deposited
in the fracture. The particulate material holds the fracture open
while still allowing fluid flow through the permeability of the
particulate. A particulate material used for this purpose is often
referred to as a "proppant." When deposited in the fracture, the
proppant forms a "proppant pack," and, while holding the fracture
apart, provides forming conductive channels through which fluids
may flow to the wellbore. For this purpose, the particulate is
selected typically selected based on two characteristics: size
range and strength.
[0042] The particulate must have an appropriate size to prop open
the fracture and allow fluid to flow through the particulate pack,
i.e., in between and around the particles making up the pack.
Appropriate sizes of particulate for use as a proppant are
typically in the range from about 8 to about 100 U.S. Standard
Mesh. A typical proppant is sand, which geologically is defined as
having a particle size ranging in diameter from about 0.0625
millimeters ( 1/16 mm) up to about 2 millimeters. (The next smaller
size class in geology is silt: particles smaller than 0.0625 mm
down to 0.004 mm in diameter. The next larger size class above sand
is gravel, with particles ranging from greater than 2 mm up to 64
mm.)
[0043] The particulate material must be sufficiently strong, e.g.,
have a sufficient compressive strength or crush resistance, to prop
the fracture open without being completely crushed by the
subterranean forces that would otherwise close the fracture.
[0044] As used herein, "particulate" means and refers to a
particulate material that is suitable for use as a proppant pack or
gravel pack, including without limitation sand or gravel, synthetic
materials, manufactured materials, and any combinations thereof.
For this purpose, "particulate" does not mean or refer to suspended
solids, silt, fines, or other types of particulate smaller than
0.0625 mm. Further, it does not mean or refer to particulate larger
than 64 mm. Of course, "particulate" also does not mean or refer to
dissolved solids. The fracture, especially if propped open by a
proppant pack, provides an additional flow path for the oil or gas
to reach the wellbore, which increases oil and gas production from
the well.
Viscosity-Increasing Agents to Help Suspend Proppant
[0045] The proppant material typically has a much higher density
than water. For example, sand has a specific gravity of about 2.
Any proppant suspended in the water will tend to separate quickly
and settle out from the water very rapidly. To help suspend the
proppant (or other particulate with a substantially different
density than water) in a water-based fracturing fluid, it is common
to use a viscosity-increasing agent for the purpose of increasing
the viscosity of water.
[0046] Viscosity is the resistance of a fluid or slurry to flow,
defined as the ratio of shear stress to shear rate. The unit of
viscosity is Poise, equivalent to dyne-sec/cm.sup.2. Because one
poise represents a relatively high viscosity, 1/100 poise, or one
centipoise ("cP"), is usually used with regard to well treatment
fluids. Viscosity must have a stated or an understood shear rate in
order to be meaningful. Measurement temperature also must be stated
or understood. As used herein, if not otherwise specifically
stated, the viscosity is measured with a Model 50 type viscometer
at a shear rate of 40 l/s and at 25.degree. C. (77.degree. F.). It
should be understood, of course, that the viscosity of any fluid
(e.g., a component fluid to be used in forming a treatment fluid),
would be determined at 40 l/s and 25.degree. C. (77.degree. F.). As
used herein, if not otherwise specifically stated, the viscosity of
a treatment fluid is measured at any point in the treatment job,
i.e., at any time between directing of the treatment fluid into the
wellbore and for so long as the pumping equipment for the treatment
fluid is on the well site for the treatment job. Of course, the
viscosity of a treatment fluid under downhole conditions may be
inferred. Further, it should be understood that the viscosity of
any fluid would be determined without particulate, i.e., without
proppant type particulate.
[0047] The viscosity of water is about 1 cP. A viscosity-increasing
agent is a chemical additive that alters fluid rheological
properties to increase the viscosity of the fluid. A
viscosity-increasing agent can be used to increase the viscosity,
which increased viscosity can be used, for example, to help suspend
a proppant material in the treatment fluid. According to certain
aspects of the present inventions, the methods are particularly
advantageously used for treatment fluids having a viscosity of less
than 100 cP at 40 l/s and 25.degree. C. (77.degree. F.) throughout
the treatment job. Treatment fluids having such low viscosity are
used in some water-frac treatments. Treatment fluids having such
low viscosity are often referred to as "base gels," which excludes,
for example, fluids that are typically referred to as "cross-linked
gels" and "surfactant gels."
[0048] Because of the high volume of fracturing fluid used in
fracturing, it is desirable to increase the viscosity of fracturing
fluids efficiently in proportion to the concentration of the
viscosity-increasing agent. Being able to use only a small
concentration of the viscosity-increasing agent requires less total
amount to achieve the desired fluid viscosity in a large volume of
fracturing fluid. Efficient and inexpensive viscosity-increasing
agents include water-soluble polymers such as guar gum. Other types
of viscosity-increasing agents may also be used for various
reasons, for example, in high-temperature applications.
[0049] The viscosity of solutions with viscosity-increasing agents
can be greatly enhanced by crosslinking the viscosity-increasing
agent with a cross-linking agent. For example, guar gum and similar
viscosity-increasing agents can be crosslinked with boric acid or
other boron containing materials. Thus, boron crosslinked guar gum
solutions are commonly used as fracturing fluids. Of course, there
are numerous other types of cross-linking agents. As discussed
herein, however, crosslinking is undesirable for certain types of
well treatments, such as a water-frac treatments. Further, the
presence of a substantial concentration of boron in the water,
either naturally occurring or in produced water may cause
undesirable cross-linking.
Friction-Reducing Agents to Help Pumpability of a Fluid
[0050] In some instances a fracturing treatment involves pumping a
proppant-free fracturing fluid into a subterranean formation.
During the pumping of the fracturing fluid into the wellbore, a
considerable amount of energy may be lost due to friction between
the treatment fluid in turbulent flow and the formation and/or
tubular goods (e.g., pipes, coiled tubing, etc.) disposed within
the wellbore. As a result of these energy losses, additional
horsepower may be necessary to achieve the desired treatment.
[0051] To reduce these energy losses, a friction-reducing agent
(sometimes called a friction reducer) may be included in the
treatment fluid. A friction-reducing agent is a chemical additive
that alters fluid rheological properties to reduce friction created
within the fluid as it flows through small-diameter tubulars or
similar restrictions. Generally, polymers or similar
friction-reducing agents add viscosity to the fluid, which reduces
the turbulence induced as the fluid flows. The friction-reducing
agent reduces the frictional losses due to friction between the
treatment fluid in turbulent flow and the tubular goods and/or the
formation: Friction-reducing agents add some viscosity to the
fluid, which reduces the turbulence induced as the fluid flows. For
friction-reducing purposes, the viscosity of a treatment fluid may
be increased only slightly, for example, from about 1 cP to a
viscosity of less than 35 cP. According to certain aspects of the
present inventions, the methods are particularly advantageously
used for treatment fluids having a viscosity of less than 35 cP at
40 l/s and 25.degree. C. (77.degree. F.) throughout the treatment
job. Treatment fluids having such very low viscosity are often used
in water-frac treatments. Treatment fluids having such very low
viscosity are often referred to as "friction-reducing fluids,"
excludes, for example, "base gel fluids," "cross-linked gels," and
"surfactant gels."
[0052] A friction reducer can also help reduce the apparent
viscosity and improve the rheological properties of a slurry, e.g.,
a water-based fluid containing a proppant. As a result, turbulent
flow can be achieved at lower pumping rates, which results in
reduced friction pressure during pumping. When the apparent
viscosity of a slurry is reduced, the slurry can be mixed at a
higher density by reductions in the amount of mix water added.
Although the slurry is denser, it remains easy to pump.
[0053] Like viscosity-increasing agents, friction-reducing agents
are often comprised of hydratable polymers. Similarly, the
friction-reducing agents are typically hydrated directly in the
water to be used in the well treatment fluid. In some cases, a
viscosity-increasing agent and a friction-reducing agent may be the
same hydratable polymer, merely used in a lower concentration for
the purpose of reducing fluid friction.
[0054] Although any friction-reducing agent may be used in the
methods according to the inventions, examples of water-soluble
friction-reducing agents include guar gum, guar gum derivatives,
polyacrylamide, and polyethylene oxide.
Elasticity-Increasing Agents to Help Pumpability of a Fluid
[0055] Elasticity pertains to a material that can undergo stress,
deform, and then recover and return to its original shape after the
stress ceases. Once stress exceeds the yield stress or elastic
limit of a material, permanent deformation occurs and the material
will not return to its original shape once the stress is removed.
Elastic behavior can depend on the temperature and the duration of
the stress as well as the intensity of the stress.
[0056] Elasticity of a fluid is a material property characterizing
the compressibility of the fluid--how easy a unit of the fluid
volume can be changed when changing the pressure working upon it.
An increase in the pressure will decrease the volume of the fluid.
A decrease in the volume will increase the density of the
fluid.
[0057] It is sometimes desirable to include a water-soluble
elasticity-increasing agent in a fracturing fluid. Again, like
viscosity-increasing agents, some elasticity-increasing agents are
sensitive to certain ions that may be present in a type or source
of water that would otherwise be most convenient to use in a
treatment fluid.
Water Fracturing
[0058] A "water frac" is a type of hydraulic fracturing in which
the present inventions are expected to have particular advantage
and benefit. A water frac is characteristically employed for low
permeability reservoirs that typically require extended-length
fractures to maximize the surface area of the fracture faces and
therefore improve production volumes and rates. A water frac is
believed to be a lower cost alternative to pumping large volumes of
proppant suspended in a viscous gelled fluid. A typical modern
water frac involves pumping very large volumes of fresh water
(e.g., 10,000 bbl or more), with relatively low concentrations of
additives, e.g., friction reducer, surfactant, and clay stabilizer,
and with relatively low particulate (e.g., sand) concentrations
(e.g., 0.5 ppg during bulk with tail-in from 0.5 to 2 ppg during
last 1-5% of job). Higher sand concentrations of proppant near the
end of the treatment help prop the fracture near the wellbore.
Since the treating fluid is primarily water (not gel), clean-up
problems sometimes experienced with conventional treatments are
minimized. The low viscosity of the water treating fluid (e.g.,
less than 100 cP at 40 l/s and at 25.degree. C. (77.degree. F.))
tends to maximize fracture length while minimizing fracture
height.
Problem with Certain Hydratable Additives and Certain Dissolved
Ions in Water
[0059] Most, if not all, of the commonly used water-soluble
viscosity-increasing agents, water-soluble friction-reducing
agents, and water-soluble elasticity-increasing agents are
comprised of a hydratable material. As used herein, a "hydratable
additive" is selected from the group consisting of: a water-soluble
viscosity-increasing agent, a water-soluble friction-reducing
agent, and a water-soluble elasticity-increasing agent.
[0060] As used herein, the term "water soluble" means at least 1%
by weight soluble in distilled water when tested at room
temperature of 68.degree. F. (20.degree. C.) and standard pressure
(1 atm).
[0061] As referred to herein, "hydratable" means capable of being
hydrated by contacting the hydratable additive with water.
Regarding a hydratable additive that comprises a polymer, this
means, among other things, to associate sites on the polymer with
water molecules and to unravel and extend the polymer chain in the
water. Viscosity-increasing agents have been conventionally
hydrated directly in the water at the concentration to be used for
the well treatment fluid.
[0062] A common problem with using hydratable additives is that
many of the commonly-used hydratable additives used for such
purposes are sensitive to dissolved ions in the water. The
hydratable additives are often especially sensitive to divalent
cations such as calcium and magnesium. For example, divalent
cations such as calcium and magnesium may inhibit and slow the time
required for hydration of certain types of polymers commonly used
for such purposes.
[0063] Water that tends to be more difficult to use with hydratable
additives is water having a concentration of dissolved alkaline
earth metal ions of more than 1,000 ppm. For example, some
hydratable polymers are difficult to hydrate in water that contains
more total dissolved solids than seawater, and sometimes the
specific type of hydratable polymer desired to be used is sensitive
to even lower concentrations of total dissolved solids. For
example, xanthan gum, which is sometimes used as a
viscosity-increasing agent, can be slow and difficult to hydrate
thoroughly in such aqueous solutions. Full hydration of the xanthan
polymer is important because incomplete hydration will impair
development of viscosity in the fluid and may also cause fine
particulate matter of incompletely hydrated xanthan gum to damage
the permeability of the formation. Hydration of xanthan in
freshwater is not usually problematic.
[0064] Furthermore, the hydratable polymer may be sensitive to
other ions, including borate ions, which in some cases and under
certain conditions can undesirably crosslink the polymer.
[0065] Therefore, in the past fracturing fluids often have required
the use of water that does not contain high concentrations of total
dissolved solids, especially high concentrations of dissolved
divalent cations. For this reason, most fracturing fluids require a
minimum quality of water. Most fracturing fluids are run in potable
or freshwater. However, potable water and freshwater is becoming
increasingly expensive and difficult to come by, especially
considering the high volumes of water required for fracturing.
[0066] To solve the problem of hydration in water having high
concentrations of TDS, especially due to high concentration of
divalent cations, another conventional approach has included
chemically modifying the hydratable polymer so that it is better
capable of hydrating in water having high TDS. Other approaches to
handling water having high concentrations of TDS were by chemical
addition to reduce the effect of salt. Another conventional
approach has included heating a brine to about 140.degree. F.
(60.degree. C.) to increase the hydration rate of the hydratable
polymer in the brine. However, heating of brine is time consuming,
expensive, and difficult to achieve in the field. Further, heating
of a brine may cause the viscosity-increasing agent to build
excessive viscosity if later subjected to high wellbore
temperatures. It can be prohibitively expensive to heat large
quantities of water.
[0067] Yet another attempted solution has been to treat the water
to remove some of the interfering ions. There are several existing
methods of treating non-freshwater such as evaporative distillation
and reverse osmosis. Both of these treatment methods remove the
vast majority of TDS from the water. The most common method of
treating water for use in a fracturing treatment is evaporative
distillation, however, this method is very expensive and often
impractical on the scale needed. Removing excess ions by reverse
osmosis is also an expensive process. Of course, the costs of
treating water are multiplied by the large volumes of water
required for well treatments, especially for the volumes of water
required for water-fracturing treatments.
Problem with Pumping Proppant-Containing Treatment Fluids
[0068] A problem with pumping a treatment fluid with a particulate,
for example, a fracturing fluid containing a proppant, is that the
sand or other type of particulate material is usually very abrasive
when pumped in a fluid moving at high pumping rates. This leads to
wear on the pumping equipment during use. The abrasiveness of the
proppant can cause erosion on metal surfaces inside pumps,
connective piping, and downhole tubulars and equipment. The erosion
is especially problematic within the pumps, where the local fluid
velocities adjacent to valves and other surfaces can be much higher
than the average velocity of the fluid being pumped through a
cylinder of the fluid end. The erosion of these surfaces causes
wear on the pumps and can result in high maintenance costs.
Water Classifications
[0069] There are various methods of describing water quality, for
example, ion types in water, their ionic strength, and total
dissolved solids. Water may also be classified based on its
source.
[0070] Solids are found in water in two basic forms, suspended and
dissolved. Suspended solids include silt, stirred-up bottom
sediment, decaying plant matter, or sewage-treatment effluent.
Suspended solids will not pass through a filter, whereas dissolved
solids will.
[0071] Total dissolved solids ("TDS") refers to the sum of all
minerals, metals, cations, and anions dissolved in water. As most
of the dissolved solids are typically salts, the amount of salt in
water is often described by the concentration of total dissolved
solids in the water.
[0072] Dissolved solids in typical freshwater samples include
soluble salts that yield ions such as sodium (Na.sup.+), calcium
(Ca.sup.2+), magnesium (Mg.sup.2+), bicarbonate (HCO.sub.3.sup.-),
sulfate (SO.sub.4.sup.2-), or chloride (Cl.sup.-). Water that
contains significant amounts of dissolved salts is sometimes
broadly called saline water or brine, and is expressed as the
amount (by weight) of TDS in water in mg/l. On average, seawater in
the world's oceans has a salinity of about 3.5%, or 35 parts per
thousand. More than 70 elements are dissolved in seawater, but only
six elements make up greater than 99% by weight.
[0073] Total dissolved solids can be determined by evaporating a
pre-filtered sample to dryness, and then finding the mass of the
dry residue per liter of sample. A second method uses a Vernier
Conductivity Probe to determine the ability of the dissolved salts
in an unfiltered sample to conduct an electrical current. The
conductivity is then converted to TDS. Either of these methods
yields a TDS value, typically reported in units of mg/L.
[0074] Hardness is a more specific measure of the dissolved calcium
(Ca.sup.+2), magnesium (Mg.sup.+2) and ferrous (Fe.sup.+2, a form
of iron) ions in water. Hardness can be quantitatively determined
by titration using standardized EDTA reagent and ammonium hydroxide
buffer, typically according to procedures of the API. The hardness
ion Ca.sup.+2 can be analyzed alone by another EDTA titration
method described by the API. Hardness ions develop from dissolved
minerals, bicarbonate, carbonate, sulfate, and chloride.
[0075] Broadly speaking, either "saline water" or "brine" is often
understood to be water containing any substantial concentration of
dissolved inorganic salts, regardless of the particular
concentration. Thus, "saline water" or "brine" may broadly refer to
water containing anywhere from about 1,000 ppm to high percentages
of dissolved salts. In fact, brines used for oil field purposes
sometimes contain total dissolved solids of up to about 10% or
higher.
[0076] More technically, however, the terms "saline water,"
"brine," and other terms regarding water may sometimes be used to
refer to more precise ranges of concentrations of TDS. Although the
specific ranges of TDS for various types of water are not
universally agreed upon, various sources have used the definitions
and ranges shown in Table 1. As used herein, unless the context
otherwise suggests, the terms for classifying water based on
concentration of TDS will generally be understood as defined in
Table 1.
TABLE-US-00001 TABLE 1 A Classification of Water Based on TDS
Concentration and Relationship to Density TDS Concentration Ranges
Density @ 20.degree. C. Lb/gal lb/gal Water Ppm (US) g/ml (US)
Potable <250 <0.0021 Freshwater <1,000 <0.0083
<0.998 <8.33 Brackish 1,000-15,000 0.0083-0.0417 Saline
15,000-30,000 0.0417-0.1251 Seawater 30,000-40,000 0.1251-0.3338
1.020-1.029 8.51-8.59 Brine >40,000 >0.3338
[0077] Potable water is water that is suitable for drinking. In
addition to having low TDS, usually required by municipalities to
be less than 250 ppm and preferably less than 100 ppm, potable
water must otherwise be suitable for drinking, for example, not
having poisons or pathogens. Potable water is usually considered to
be freshwater, but not all freshwater is considered to be potable
water. While potable water is rarely required for fracturing fluids
or other types of treatment fluids, it may be used if conveniently
and economically available, for example, for purchase from a local
water district or municipality. Nevertheless, potable water is
usually the most expensive type of water, and its use for well
operations or treatments is most likely to become increasingly
restricted.
[0078] Water may also be classified based on its source.
Classifying water based on its source is a classification that is
independent of the classification based on a particular parameter,
such as TDS. Sources of water are listed in Table 2.
TABLE-US-00002 TABLE 2 A Classification of Water Based on Source
Water Source TDS concentration surface water water on land, e.g.,
Usually freshwater levels streams, lakes. ground water the ground,
e.g., from a Usually freshwater levels freshwater well Seawater
Ocean or sea Seawater levels connate water or water trapped in the
pores Any, but usually at least fossil water of the rock during
brackish levels formation of the rock formation water water found
in the pore Any, but usually at least or interstitial spaces of a
rock, and might brackish levels water not have been present when
the rock was formed returned water returned water from a Any, but
usually at least treatment fluid introduced brackish levels into an
oil or gas well produced water produced from a oil or gas Any, but
usually at least well that is not a treatment brackish levels
fluid
[0079] Due to a number of factors, the range of TDS concentrations
in naturally-occurring surface water, such as freshwater, brackish
water, saline water, and seawater, can vary considerably within the
defined ranges for the type of water. Water that is not naturally
occurring can be similarly classified by the concentration of TDS,
of course, which is generally with reference to the concentrations
of TDS in the various types of naturally-occurring water.
[0080] Non-potable water that may be suitable for treatment fluids
that include a hydratable polymer sensitive to certain dissolved
ions includes freshwater, brackish water, saline water, and
seawater. Of course, if locally available, brackish water or
seawater is relatively cheap. However, some of the polymers used in
treatment fluids are sensitive to the levels of TDS or specific
ions at concentrations higher than found in freshwater.
[0081] The typical composition of seawater is shown in Table 3.
TABLE-US-00003 TABLE 3 Typical Composition of Seawater % Weight
Concentration Dissolved Ion of TDS mg/l Chloride (Cl.sup.-) 55.04
19,400 Sodium (Na.sup.+) 30.61 10,800 Potassium (K.sup.+) 1.10 392
Magnesium (Mg.sup.2+) 3.69 1290 Calcium (Ca.sup.2+) 1.16 411
Sulfate (SO.sub.4.sup.2-) 7.68 904
[0082] Typically, although not necessarily, the salt in saline
water or brine (as those terms may be broadly used), is understood
to be mostly sodium chloride (common salt). However, water is
sometimes more specifically classified based on the type of salt
predominating in the brine, e.g., chloride brines (that is,
including a substantial concentration of calcium chloride, either
alone or in addition to sodium chloride), bromide brines, and
formate brines.
[0083] The solubility of certain salts (that is, the combined
ions), such as sodium chloride, is much higher than the
concentration of salts found in seawater. For reference, the
solubility of a few common salts is shown in Table 4.
TABLE-US-00004 TABLE 4 Solubility of Common Salts Solubility
Solubility mg/l lb/gal (US) Salt @ 20.degree. C. @ 20.degree. C.
Sodium Chloride 359,000 0.79 Magnesium Chloride 543,000 1.12
Calcium Chloride 745,000 1.64
[0084] Water containing dissolved solids has a higher density than
pure water, depending on the nature and concentration of the
dissolved solids. The more dissolved solids, the higher the density
of the water. This high solubility of certain salts can be used to
form aqueous solutions having densities much higher than that of
seawater, which may be of use in certain well treatments. For
example, the density of freshwater water when measured 20.degree.
C. (68.degree. F.) and 1 atmosphere pressure is 8.33 lb/gal (0.998
g/cm.sup.3). In comparison, the density of surface seawater ranges
from about 8.51-8.59 lb/gal (1.020 to 1.029 g/cm.sup.3), depending
on the temperature and salinity. The average density of seawater at
the surface of the ocean when measured at 1 atmosphere pressure and
22.degree. C. (72.degree. F.) is about 8.54 lb/gal (1.025
g/cm.sup.3). The amount of salts in seawater is typically in the
range of about 3.1-3.5 wt % (31,000-35,000 ppm). Depending on the
type of dissolved salts and the concentrations, the density of
brine can be higher than 15 lb/gal.
[0085] In the context of hydratable polymers, water having total
dissolved solids of less than 0.67 lb/gal (303,000 mg/l), such that
the density of the water with the total dissolved solids is less
than 9.0 lb/gal, is generally considered not too high for many
types of hydratable polymers, although some hydratable polymers may
be sensitive to lower concentrations of TDS.
Potential Sources of Water for Use in Treatment Fluids
[0086] Non-freshwater sources of water can include surface water
ranging from brackish water to seawater, returned water (sometimes
referred to as flowback water) from the delivery of a treatment
fluid into a well, and produced water.
[0087] In the production of oil and gas, great quantities of water
are produced. Sources of produced water can include water that may
have been introduced into the subterranean formation as part of a
well-completion or well-treatment process, water that may have been
delivered as part of an injection-well driving process, formation
water, and any mixture of any of these. For example, for every
barrel of oil produced from a well, it is typical to also obtain
about 10 barrels of produced water. Large quantities of produced
water continue to be disposed of as waste water, for example, by
re-injecting the produced water into a well.
[0088] With the rising demand for potable water and freshwater,
increasing public concern for the environment, and with the rising
costs of obtaining potable water and freshwater, it would be
desirable to be able to use lower quality water, such as returned
water and produced water, in well treatments.
[0089] Unfortunately, returned water and produced water often has
high concentrations of total dissolved solids (salts), and may have
TDS levels of brackish water, saline water, seawater, or brine.
Returned water and produced water may also contain hydrocarbon and
other materials. For example, in addition to dissolved and
suspended solids, produced water may also contain residual oil,
grease, and production chemicals. A production chemical is a
chemical that was introduced into the subterranean formation in a
prior well treatment and may be found in subsequently produced
water. According to this invention, it is recognized that, in
general, for water to be suitable for use in common well
treatments, usually all that is required is that the water does not
contain one or more materials that would be particularly
detrimental to the chemistry involved in such well treatments. The
water also preferably is cleaned of undissolved, suspended solids
(e.g., silt) to a point that the natural permeability and the
conductivity of the fracture will not be damaged. For this purpose,
all the water used in a well treatment may be filtered to help
reduce the concentration of undesirable suspended, undissolved
solids that may be present in the water, such as silt. Further, it
is recognized that it is even possible to use such water having
undesirable concentrations of certain ions or TDS if the water is
used as part of the treatment fluid, and the treatment fluid is
formed in using the water in a proper sequence.
[0090] Of particular concern for use in common well treatment is
the avoidance of water containing undesirably-high concentrations
of inorganic ions having a valence state of two or more. As is well
known in the oil and gas industry, such ions can interfere with the
chemistry of forming or breaking certain types of viscous fluids
that are commonly used in various well treatments.
[0091] Cations that are of common concern include dissolved
alkaline earth metal ions, particularly calcium and magnesium ions,
and may also include dissolved iron ions.
[0092] An anion of common concern includes sulfate.
[0093] Normally, however, a high concentration of both calcium ions
and sulfate anions in a water source is unlikely. Calcium ions tend
to react with sulfate ions to produce calcium sulfate, which is an
insoluble salt that tends to precipitate from solution. Similarly,
strontium ions and sulfate ions or barium ions and sulfate ions
tend to combine and precipitate. Thus, a problem with using water
for common well treatments tends to be either an undesirably-high
concentration of calcium, strontium, or barium ions or an
undesirably-high concentration of sulfate ions.
[0094] Borates have the chemical formula B(OR).sub.3, where
B=boron, O=oxygen, and R=hydrogen or any organic group. At higher
pH ranges, e.g., 8 or above, a borate is capable of increasing the
viscosity of an aqueous solution of a water-soluble polymeric
material such as a galactomannan or a polyvinyl alcohol.
Afterwards, if the pH is lowered, e.g., below 8, the observed
effect on increasing the viscosity of the solution can be reversed
to reduce or "break" the viscosity back toward its original lower
viscosity. It is also well known that, at lower pH ranges, e.g.,
below 8, borate does not increase the viscosity of such a
water-soluble polymeric material. This effect of borate and
response to pH provides a commonly-used technique for controlling
the cross-linking of certain polymeric viscosity-increasing agents.
The control of increasing the viscosity of such fluids and the
subsequent "breaking" of the viscosity tends to be sensitive to
several factors, including the particular borate concentration in
the solution.
[0095] Without being limited by any particular theoretical
explanation, a borate is believed to be capable of forming labile
bonds with two alcohol sites of other molecules. This ability of a
borate to react with the alcohol sites can be employed to
"cross-link" alcohol sites on different polymer molecules (or
possibly other parts of the same molecule) that find their way in a
solution to become adjacent to one another. The pH of an aqueous
solution controls the equilibrium between boric acid and borate
anion in solution. At higher pH ranges, the equilibrium shifts
toward a higher concentration of borate ion in the water.
[0096] For example, by increasing the pH of a fluid to 8 or above,
although usually in the range of about 8.5-12, a borate-releasing
compound such as boric acid releases borate ions, which become
available for cross-linking a water-soluble polymer having alcohol
sites. By subsequently lowering the pH of the fluid to a pH of
below 8, for example, by adding or releasing an acid into the
fluid, the equilibrium shifts such that less of the borate anion
species is in solution, and the cross-linking can be broken,
thereby returning such a gelled fluid to a much lower
viscosity.
[0097] Regardless of the theoretical chemical mechanism of borate
cross-linking, which may not yet have been perfectly elucidated and
understood, borates are widely used in the oil and gas industry to
selectively control an increase and subsequent break in the
viscosity of a water-based treatment fluid containing a
water-soluble polymeric material having alcohol sites. A fluid
having a viscosity greater than that of water can be useful in
various well treatments, such as in fracturing a well where the
increased viscosity is used to help carry a proppant through a
wellbore to a desired location. After having served the intended
purpose of a fluid having an increased viscosity, the viscosity of
the fluid can be broken to help return the fluid back to the
surface as some of the produced water. Therefore, borates are
commonly found in produced water.
[0098] Borate cross-linking may be undesirable in some well
treatments, however, which may interfere with the desired chemistry
for a particular well treatment. Thus, the presence of borates or
the presence of unknown concentrations of borates is often
undesired.
[0099] Borates also may be naturally occurring in freshwater,
seawater, and formation water, any of which may be found in treated
wells, but usually in such low concentrations that the borates
normally would not be expected to interfere with the chemistry of
common treatment fluids. As borates are often used in various
treatment fluids, however, undesirably high concentrations of
borates are likely to be present in produced water.
[0100] As used herein, a substantial concentration of sulfate ions
is defined as being equal to or greater than 500 ppm; a substantial
concentration of calcium or magnesium ions is defined as being
equal to or greater than a combined total of 1,000 ppm; a
substantial concentration of iron ions is defined as being equal to
or greater than 10 ppm; a substantial concentration of borate is
defined as being equal to or greater than 5 ppm.
Using Lower-Quality Water for a Portion of the Treatment Fluid
[0101] There may come a time when potable water available for use
for fracturing and other well treatments is severely restricted. A
first aspect of the inventions generally relates to using
lower-quality water for a portion of the water to be used in a
treatment fluid. This allows the use of non-potable water and
non-freshwater for a portion of the well treatment, which are less
likely to become costly or usage restricted.
[0102] More particularly, the first aspect of the inventions
generally relates to treating a portion of the water to be used in
a treatment fluid. According to one embodiment of this aspect, the
method comprises the steps of continuously: (a) pumping a first
fluid comprising a first aqueous solution; (b) pumping a second
fluid comprising a second aqueous solution; (c) merging at least
the first and second fluids to form a treatment fluid comprising a
merged aqueous solution, wherein the merged aqueous solution
comprises at least 25% by weight of the first aqueous solution and
at least 25% by weight of the second aqueous solution, and wherein
the merged aqueous solution has a viscosity of less than 100 cP at
40 l/s and at 25.degree. C. (77.degree. F.); and (d) directing the
treatment fluid into the wellbore.
[0103] According to one embodiment of this first aspect of the
inventions: (i) the merged aqueous solution has a merged
concentration of at least one component selected from the group
consisting of: a dissolved ion, oil, grease, a production chemical,
and suspended solids; (ii) the first aqueous solution has a
concentration of the at least component that is substantially lower
than the merged concentration of the at least one component; and
(iii) the second aqueous solution has a concentration of the at
least one component that is substantially higher than the merged
concentration of the at least one component. According to a
preferred embodiment, the component is at least one dissolved ion.
Preferably, the first fluid comprises a first concentration of a
hydratable additive and the second fluid has a second concentration
of the hydratable additive that is substantially lower than the
first concentration of the hydratable additive.
[0104] According to another embodiment of this first aspect of the
inventions: (i) the merged aqueous solution has a merged
concentration of total dissolved solids; (ii) the first aqueous
solution has a concentration of total dissolved solids that is
substantially lower than the merged concentration of total
dissolved solids; and (iii) the second aqueous solution has a
concentration of total dissolved solids that is substantially
higher than the merged concentration of total dissolved solids.
Preferably, the first fluid comprises a first concentration of a
hydratable additive and the second fluid has a second concentration
of the hydratable additive that is substantially lower than the
first concentration of the hydratable additive.
[0105] A treatment fluid having a merged viscosity of less than 100
cP at 40 l/s and at 25.degree. C. (77.degree. F.) is particularly
useful in some water-frac treatments. A treatment fluid having a
merged viscosity of less than 50 cP is useful in most water-frac
treatments.
[0106] Preferably, the first fluid is comprised of at least 50% by
weight of the first aqueous solution and wherein the second fluid
is comprised of at least 50% by weight of the second aqueous
solution.
[0107] According to a preferred embodiment, the step of merging is
under sufficient conditions to form the treatment fluid to comprise
at least 25% by weight of the first aqueous solution and at least
25% by weight of the second aqueous solution.
[0108] Typically, the step of pumping the first fluid or the step
of pumping the second fluid comprises using more than one fluid
pump.
Treating Lower-Quality Water for Use as a Portion of a Treatment
Fluid
[0109] A second aspect of the inventions generally relates to
treating a base aqueous solution to obtain a first aqueous
solution, for example, to have a substantially reduced
concentration of at least one component relative to the
concentration of the at least one component in the base aqueous
solution, and using the first aqueous solution and a lower-quality
water, such as the base aqueous solution, to form a treatment
fluid. The component is selected for being deleterious to the use
or performance of a treatment fluid. More particularly, the
component is selected from the group consisting of: a dissolved
ion, oil, grease, a production chemical, and suspended solids. This
allows the use of lower-quality water for some of the water
required for making up the treatment fluid, without requiring
treating of all the base aqueous solution. The first aqueous
solution and the lower-quality water are merged after pumping the
fluid portions toward the wellbore.
[0110] According to one embodiment of this second aspect of the
inventions, a method of forming and delivering a treatment fluid
into a wellbore is provided, the method comprising the steps of:
(a) treating a base aqueous solution to obtain the first aqueous
solution having a substantially reduced concentration of at least
one component relative to the concentration of the at least one
component in the base aqueous solution, wherein the component is
selected from the group consisting of: a dissolved ion, oil,
grease, a production chemical, and suspended solids; (b) pumping a
first fluid comprising the first aqueous solution; (c) pumping a
second fluid comprising a second aqueous solution; (d) merging at
least the first and second fluids to form a treatment fluid
comprising a merged aqueous solution, wherein the merged aqueous
solution comprises at least 25% by weight of the first aqueous
solution and at least 25% by weight of the second aqueous solution,
and wherein the merged aqueous solution has a merged viscosity of
less than 100 cP at 40 l/s and at 25.degree. C. (77.degree. F.);
and (e) directing the treatment fluid into the wellbore. More
particularly, (i) the merged aqueous solution has a merged
concentration of the at least one component; (ii) the first aqueous
solution has a concentration of the at least one component that is
substantially lower than the merged concentration of the at least
one component; and (iii) the second aqueous solution has a
concentration of the at least one component that is substantially
higher than the merged concentration of the at least one component.
Preferably, the component is at least one dissolved ion.
[0111] According to another embodiment of this second aspect of the
inventions, a method of forming and delivering a treatment fluid
into a wellbore is provided, the method comprising the steps of:
(a) treating a base aqueous solution to obtain the first aqueous
solution having a substantially reduced concentration of total
dissolved solids relative to the concentration of the total
dissolved solids in the base aqueous solution; (b) pumping a first
fluid comprising the first aqueous solution; (c) pumping a second
fluid comprising a second aqueous solution; (d) merging at least
the first and second fluids to form a treatment fluid having a
merged aqueous solution, wherein the merged aqueous solution
comprises at least 25% by weight of the first aqueous solution and
at least 25% by weight of the second aqueous solution, and wherein
the merged aqueous solution has a merged viscosity of less than 100
cP at 40 l/s and at 25.degree. C. (77.degree. F.); and (e)
directing the treatment fluid into a wellbore. More particularly,
(i) the merged aqueous solution has a merged concentration of total
dissolved solids; (ii) the first aqueous solution has a
concentration of total dissolved solids that is substantially lower
than the merged concentration of total dissolved solids; and (iii)
the second aqueous solution has a concentration of total dissolved
solids that is substantially higher than the merged concentration
of total dissolved solids
[0112] It should be understood that several different types of
treating are available for selectively and partially treating water
to remove an undesirable component. The step of treating a portion
of the water preferably comprises selectively exchanging at least
one dissolved ion for another ion having a different valence. This
step of treating is to selectively reduce the concentration of the
dissolved ion in the water that is likely to interfere with
treatment fluid performance, especially fracturing fluid
performance, instead of removing the majority of the ions. More
particularly, this invention includes selectively reducing the
concentration of a component, such as one or more ions, that
interfere with the performance of the treatment fluid. For example,
this may include selectively exchanging at least one dissolved ion
for another ion having a different valence. Further, this invention
recognizes that and takes advantage of the possibility of treating
only a portion of the total amount of water required for a well
operation or treatment.
[0113] Preferably, the at least one ion is selected from the group
consisting of calcium, magnesium, sulfate, iron, and borate.
According to a preferred embodiment of the invention, the base
aqueous solution has a substantial concentration of sulfate ions of
equal to or greater than 500 ppm; a substantial concentration of
calcium or magnesium ions of equal to or greater than a combined
total of 1,000 ppm; a substantial concentration of iron ions of
equal to or greater than 10 ppm; or a substantial concentration of
borate ions of equal to or greater than 5 ppm.
[0114] Selectively removing or exchanging certain ions is also more
cost effective than removing the majority of the dissolved ions.
There are numerous ways to accomplish this. One method is to
exchange the divalent ions with monovalent ions. By chemically
performing these substitutions, the treated water is made
compatible with fracturing fluids.
[0115] For example, the ions Mg.sup.+2 and Fe.sup.+2 can be removed
by raising the pH (with NaOH or KOH) and then allowing the
precipitated Fe(OH).sub.2 and Mg(OH).sub.2 to settle out. Calcium
hardness can be removed by adding excess sodium carbonate to
precipitate Ca.sup.+2 as CaCO.sub.3. Temporary hardness is caused
by bicarbonate salts, which can be removed by boiling the water and
leaving behind a calcium carbonate solid. Hard water can be passed
through an ion exchange column where hardness ions are captured on
the resin. Removal of hardness is the process called water
softening. Methods for treating produced water or other type of
water to reduce concentrations of certain undesirable ions are also
more particularly disclosed in U.S. application patent Ser. No.
11/899,299 filed Sep. 5, 2007, entitled "Mobile Systems and Methods
of Sufficiently Treating Water So That the Treated Water May Be
Utilized in Well Treatments," and having for named inventors Billy
Slabaugh (now deceased), Arron Karcher, Michael Segura, Randy
Rosine, and Max Phillippi, which is herein incorporated by
reference in its entirety. If there is any difference or conflict
between the definition or usage of a term in this specification and
the specification of another document incorporated herein by
reference, the definition or usage of this specification will
control.
[0116] To reduce all types of dissolved solids in an aqueous
solution, less selective methods such as evaporative methods can be
used.
[0117] Treating produced water or other type of water to reduce any
substantial concentrations of one or more of the dissolved sulfate,
calcium, strontium, or barium, magnesium, and iron ions, and
possibly to reduce any substantial concentrations of borates, may
obtain sufficiently treated water for use in many common well
treatments. If not specified, water to be treated can be of any
source, but is understood to not be suitable for well treatments
due to the presence of a substantial concentration of any one or
more of the following ions: calcium and magnesium ions, iron ions;
sulfate ions; and borate ions.
[0118] As used herein, the term "treated water" means water that
has been treated according to any one of the various treatment
systems or methods to reduce the concentration of at least one ion
in the water, unless the context otherwise requires. Of course, the
treated water according to the systems and methods of the present
invention would not be expected to be potable nor suitable for
purposes other than treatment fluids. Saving the cost of
unnecessary water purification for use of the water in well
treatments, however, is expected to be of enormous economic and
practical benefit.
[0119] According to a preferred embodiment, the base aqueous
solution is selected for having a concentration of total dissolved
solids of greater than 40,000 ppm. According to a more preferred
embodiment, the first aqueous solution is treated at least
sufficiently to have a concentration of total dissolved solids of
less than 30,000 ppm. According to a more preferred embodiment, the
second aqueous solution is selected for having a concentration of
total dissolved solids of greater than 40,000 ppm. Conveniently,
the base aqueous solution can be selected to be the same as the
second aqueous solution. For example, each of the base and the
second aqueous solutions is preferably selected from the group
consisting of brine, returned water, produced water, or any
combination thereof in any proportion.
[0120] Preferably, the treating of the water is performed using a
mobile treatment system at or near the well site using a base
aqueous solution that is of lower-quality water and readily
available near the well site.
[0121] According to further preferred embodiments of this second
aspect of the invention, the first fluid comprises a first
concentration of a hydratable additive and the second fluid has a
second concentration of the hydratable additive that is
substantially lower than the first concentration of the hydratable
additive.
Prehydrating of Hydratable Additive
[0122] As described above, some types of viscosity-increasing
agents and friction-reducing agents are sensitive to certain ions
commonly found dissolved in various types of water. The third
aspect of the inventions generally relates to prehydrating an
unhydrated hydratable additive in water having a lower
concentration of certain ions that can interfere with hydration of
the hydratable additive and then mixing the prehydrated additive
with water having a higher concentration of such ions. According to
this aspect of the inventions, the method comprises the steps of:
(a) forming a premix fluid comprising: (i) an unhydrated hydratable
additive; and (ii) a first aqueous solution; (b) subsequently
forming a treatment fluid comprising: (i) the premix fluid; and
(ii) a second aqueous solution; and (c) simultaneously with or
subsequently to the step of forming the treatment fluid, delivering
the treatment fluid into the wellbore.
[0123] According to one embodiment of this third aspect of the
inventions: (i) the first aqueous solution has a concentration of
at least one ion that is substantially lower than the concentration
of the at least one ion in the second aqueous solution; and (ii)
the treatment fluid has a merged viscosity of less than 100 cP at
40 l/s and at 25.degree. C. (77.degree. F.). According to a more
preferred embodiment, the at least one ion is selected from the
group consisting of calcium, magnesium, sulfate, iron, and
borate.
[0124] According to another embodiment of this third aspect of the
inventions: (i) the first aqueous solution has combined dissolved
calcium and magnesium ions of less than 10,000 ppm; and (ii) the
second aqueous solution has combined dissolved calcium and
magnesium ions of greater than 15,000 ppm; and (iii) the treatment
fluid has a merged viscosity of less than 100 cP at 40 l/s and at
25.degree. C. (77.degree. F.). According to a more preferred
embodiment, the first aqueous solution has combined dissolved
calcium and magnesium ions of less than 5,000 ppm. According to a
presently most preferred embodiment, the first aqueous solution has
combined dissolved calcium and magnesium ions of less than 1,000
ppm.
[0125] According to yet another embodiment of this third aspect,
(i) the first aqueous solution has total dissolved solids of less
than 30,000 ppm; and (ii) the second aqueous solution has total
dissolved solids of greater than 40,000 ppm; and (iii) the
treatment fluid has a merged viscosity of less than 100 cP at 40
l/s and at 25.degree. C. (77.degree. F.). According to a
more-preferred embodiment, the first aqueous solution has total
dissolved solids of less than 15,000 ppm. According to a presently
most-preferred embodiment, the first aqueous solution has total
dissolved solids of less than 1,000 ppm.
[0126] As used herein, "hydratable" means that, when a material is
mixed with water, it absorbs water to form a hydrate.
[0127] According to this aspect of the inventions, a hydratable
polymer is initially used in a substantially unhydrated state. As
used herein, this means that the hydratable polymer is less than
20% hydrated. Preferably, the unhydrated hydratable polymer is
substantially dry, that is, less than 15% hydrated.
[0128] "Percent hydration" can be measured and determined based on
the total capacity of the material to be hydrated with water. For
viscosity-increasing agents, "percent hydration" can be measured
and determined as development of a percentage of the viscosity that
the polymer would achieve when fully hydrated. To illustrate, if
the maximum viscosity reached at full hydration is 22 centipoise at
a certain temperature and shear rate, then 50% hydration is
achieved when the viscosity reaches 11 centipoise at the same
temperature and shear rate. Here, one centipoise is equivalent to
one millipascal second (mPa-s). For a given polymer system at a
given temperature in a given mixing system, the time to full
hydration can be readily determined experimentally or empirically.
From the time of mixing with water to full hydration, the time to
partial hydration degrees such as 70% and less can likewise be
determined. Finally, from the time to partial hydration, the size
of the mixing tanks is determined based on the residence calculated
from the desired flow rate. The system is said to be sized to
achieve a residence time needed to achieve a hydration degree of,
for example, about 75%, etc. Naturally, all result-effective
variables are taken into consideration when sizing the tanks. These
include without limitation flow rate, degree of shear, temperature,
nature of the polymer thickener, and so on.
[0129] A hydratable polymer is preferably water soluble. As used
herein, this means at least 1% by weight soluble in distilled water
at 68.degree. F. (20.degree. C.) and 1 atm pressure.
[0130] Preferably, the unhydrated hydratable additive is selected
from the group consisting of a viscosity-increasing agent, a
friction reducer, and any combination thereof in any proportion.
According to a preferred embodiment, the unhydrated hydratable
additive is selected despite being sensitive to hydration in the
presence of calcium or magnesium ions, such that the step of
forming a premix fluid allows the use of a lower concentration of
hydratable polymer in the treatment fluid to achieve the desired
degree of effect from the hydratable polymer in the treatment fluid
than would be required to hydrate the unhydrated hydratable polymer
in the second aqueous solution under similar conditions. Some types
of hydratable polymers, e.g., xanthan gums and certain types of
friction reducers do not hydrate properly if the TDS concentration
is too high, especially when the high TDS is due to the high
concentration of divalent cations.
[0131] According to preferred embodiments of this aspect of the
inventions, the first aqueous solution is selected from the group
consisting of treated water, potable water, freshwater or any
combination thereof in any proportion. Preferably, the second
aqueous solution is selected from the group consisting of brine,
returned water, produced water, or any combination thereof in any
proportion.
[0132] Preferably, the step of forming the premix fluid is under
conditions sufficient to form a premix fluid comprised of at least
50% by weight of the first aqueous solution. The step of forming
the premix fluid preferably further comprises mixing under at least
sufficient conditions of concentration of the unhydrated hydratable
additive in the first aqueous solution, shear, time, temperature,
and pH for the hydratable additive to hydrate greater than 50% when
measured by viscosity prior to the step of forming a treatment
fluid, whereby the mixing conditions help avoid the formation of
gel balls (aka "fish eyes"). More preferably, the hydratable
additive is hydrated to greater than 70% hydration when measured by
viscosity prior to the step of forming a treatment fluid. In
various embodiments, the unhydrated hydratable additive is sifted
into a water solution or added to water as an emulsion in a carrier
fluid such as petroleum oil.
[0133] Preferably, the step of forming a treatment fluid is under
sufficient conditions to form the treatment fluid to comprise at
least 25% by weight of the first aqueous solution and at least 25%
by weight of the second aqueous solution, and in combination at
least 50% by weight of the first and second aqueous solutions.
[0134] Advantageously, the temperature of the fluids used in the
methods is from about 34.degree. F. (1.degree. C.) to about
122.degree. F. (50.degree. C.), and more preferably from about
34.degree. F. (1.degree. C.) to about 95.degree. F. (35.degree.
C.).
[0135] Preferably, the step of delivering the treatment fluid is
within a relatively short period after forming the treatment fluid,
e.g., one hour. More preferably, the step of delivering the
treatment fluid is immediately after the step of forming a
treatment fluid ("on the fly"), whereby the higher concentration of
calcium and magnesium ions in the treatment fluid from the second
aqueous solution does deleteriously effect the hydratable additive
during the short time from forming the treatment fluid until the
treatment fluid reaches a desired location down the wellbore.
[0136] It should be understood that the step of delivering the
treatment fluid into the wellbore can advantageously include the
use of more than one fluid pump.
[0137] For example, when performing a well treatment, such as a
water-fracturing treatment, there would be two separate types of
water employed, one of which had a higher-water quality in terms of
having lower concentration of one or more certain specific ions or
TDS than the other. Since most hydratable additives do not hydrate
as quickly or completely in water which has high concentrations of
certain ions or high TDS, the hydratable additive is prehydrated in
the higher-quality water. Once the hydratable additive is
prehydrated to the desired degree, it would then be mixed with the
lower-quality water for further use. As discussed herein, there are
numerous sources of lower-quality water (e.g., water having a high
concentration of TDS), such as brine, produced water, and flowback
water. The prehydrated additive in the higher-quality water will be
concentrated above its final usage concentration since it will be
diluted with lower-quality water to form the final treatment fluid.
The prehydrated polymer may be brought to location in a prehydrated
state, mixed in tanks on location, or prehydrated on the fly in
various hydration devices. Both traditional viscosity-increasing
agents and friction-reducing agents will benefit from the
inventions. For example, it is believed that a prehydrated friction
reducer can outperform a friction reducer designed for water having
a high concentration TDS at a lower cost.
[0138] Preferably, the methods according this third aspect of the
inventions further include a step of treating a base aqueous
solution to obtain the first aqueous solution having a
substantially reduced concentration of at least one ion relative to
the base aqueous solution. Preferably, the base aqueous solution is
selected to be the same as the second aqueous solution.
Adding Crosslinker, Breaker, Surfactant, Proppant, and Other
Additives
[0139] Optionally, one or more other additives may be included to
form a treatment fluid to be delivered into a wellbore for various
purposes, for example, to stimulate the formation. Such additives
are typically introduced or mixed into the fluid at a point after
hydration of the hydratable additive begins. Normally, there is a
time of several minutes before the treatment fluid pumped into the
wellbore reaches the formation.
[0140] An example of another type of additive is a crosslinking
agent. The viscosity of solutions of guar gum and other
viscosity-increasing agents (sometimes referred to as "thickeners")
can be greatly enhanced by crosslinking them. One example of a
crosslinking agent is boric acid. During this time, the
incompletely hydrated polymer can continue to develop toward a
fully crosslinked viscosity, despite that it may have been
crosslinked at less-than-full hydration. In various embodiments,
the boron crosslinking agent is also provided in the polymer stream
as a mixture of dry ingredients or as part of the petroleum oil
emulsion.
[0141] Fluids used in the invention also may include a breaker,
although not commonly used in water-frac treatments. A breaker is a
chemical used for the purpose of diminishing or "breaking" the
viscosity of the fluid so that this fluid can be recovered more
easily from the formation during cleanup. With regard to breaking
down viscosity, oxidizers, enzymes, or acids may be used. Breakers
reduce the polymer's molecular weight by the action of an acid, an
oxidizer, an enzyme, or some combination of these on the polymer
itself. In the case of borate-crosslinked gels, increasing the pH,
and, therefore, increasing the effective concentration of the
active crosslinker, the borate anion, reversibly creates the borate
crosslinks. Lowering the pH can eliminate the borate/polymer bonds.
At a high pH above 8, the borate ion exists and is available to
crosslink and cause gelling. At a lower pH, the borate is tied up
by hydrogen and is not available for crosslinking, thus, increases
in viscosity due to crosslinking by borate ion is reversible.
[0142] The fluids used according to various embodiments of the
inventions may also include suspended material, such as proppant.
Proppant particles carried by the treatment fluid remain in the
fracture created, thus, propping open the fracture when the
fracturing pressure is released and the well is put into
production. Suitable proppant materials include, but are not
limited to, sand, walnut shells, sintered bauxite, glass beads,
ceramic materials, naturally-occurring materials, or similar
materials. Mixtures of proppants can be used as well. If sand is
used, it typically will be from about 20 to about 100 U.S. Standard
Mesh in size. With synthetic proppants, mesh sizes about 8 or
greater may be used. The concentration of proppant in the fluid can
be any concentration known in the art, and preferably will be in
the range of from about 0.03 to about 3 kilograms of proppant added
per liter of liquid phase (0.25-25 lb/gal). Also, any of the
proppant particles can be coated with a resin to potentially
improve the strength, clustering ability, and flow-back properties
of the proppant.
[0143] Some fluids used in the invention may also include a
surfactant. For example, a surfactant may be used for its ability
to aid the dispersion and/or stabilization of a gas component into
the fluid. Viscoelastic surfactants are also suitable for use in
the treatment fluids.
[0144] A fiber component may be included in the fluids used in the
inventions to achieve a variety of properties including improving
particle suspension, particle transport capabilities, and gas phase
stability. Fibers used may be hydrophilic or hydrophobic in nature,
but hydrophilic fibers are preferred. Fibers can be any fibrous
material. The fiber component may be included at concentrations
from about 1 to about 15 grams per liter of the liquid phase of the
fluid, preferably the concentration of fibers are from about 2 to
about 12 grams per liter of liquid, and more preferably from about
2 to about 10 grams per liter of liquid
[0145] Fluids used in the invention may further contain other
additives and chemicals that are known to be commonly used in oil
field applications by those skilled in the art. These include, but
are not necessarily limited to, breaker aids, co-surfactants,
oxygen scavengers, alcohols, scale inhibitors, corrosion
inhibitors, fluid-loss additives, oxidizers, bactericides,
biocides, and the like.
Pumping at Different Average Bulk Fluid Velocities
[0146] Conventionally, a fluid is created on the surface and pumped
as a single stream by an array of high-horsepower pumps through a
manifold near the well head.
[0147] The fourth aspect of the inventions generally relates to
pumping a first fluid having either no particulate or a relatively
low concentration of a particulate suspended therein and pumping a
second fluid having a relatively high concentration of the
particulate suspended therein, and then merging at least the first
and second fluids to form a treatment fluid having a merged
concentration of the particulate. According to this fourth aspect,
the method comprises the steps of: (a) pumping a first fluid
comprising a first aqueous solution with a first
positive-displacement pump; (b) pumping a second fluid comprising a
second aqueous solution with a second positive-displacement pump;
(c) merging at least the first and second fluids to form a
treatment fluid; and (d) directing the treatment fluid into a
wellbore. For this aspect of the inventions: (i) the treatment
fluid comprises a merged concentration of a particulate; (ii) the
first fluid comprises a first concentration of the particulate that
is substantially higher than the merged concentration of the
particulate; (iii) the second fluid comprises a second
concentration of particulate that is substantially lower than the
merged concentration of the particulate; and (iv) the first fluid
is pumped at a substantially lower average bulk fluid velocity
through the first pump than the average bulk fluid velocity at
which the second fluid is pumped through the second pump.
[0148] In an embodiment of this aspect, the fluid stream is kept in
multiple streams (i.e., 2 or more separate streams) where the
stream containing the higher concentration of particulate is
separate from another fluid stream containing the lower
concentration of particulate (or no particulate) until the separate
fluid streams have passed through the pumping equipment. At this
point, the separate fluid streams have been transformed from
low-pressure fluid streams to high-pressure fluid streams. These
fluid streams may be merged into a single stream to form the
treatment fluid having a desired flow rate and pressure for the
well treatment. The fluid streams may be merged as they are
directed to the wellbore, as they enter into the wellbore, or as
they move through the wellbore.
[0149] If the fluid streams are merged prior to moving through the
wellbore, the merged stream of the treatment fluid may be
partitioned into two or more conduits for directing to the well
bore. This is done to keep the bulk fluid velocity of a fluid
moving through a conduit below 32 feet per second (9.75 meters per
second). The partitioned streams are then merged again into a
single stream of the treatment having a combined flow rate and
pressure at the wellhead or as the partitioned streams of the
treatment fluid move through the wellbore toward a subterranean
formation to be treated.
[0150] The volumetric flow rate of a fluid is determined by the
bulk fluid velocity of a fluid moving perpendicularly through a
given area (e.g., the cross-section of a tubular). Thus, the bulk
fluid velocity is directly proportional to the volumetric flow
rate. Of course, the local fluid velocities adjacent to valves and
other surfaces can be much higher than the bulk fluid velocity of
the fluid being pumped.
[0151] According to general pumping relationships, volumetric flow
rate (e.g., in units of gallons per minute) is directly
proportional to the pump speed; the discharge head is directly
proportional to the square of the pump speed; and the power
required by the pump motor is directly proportional to the cube of
the pump speed. In a positive-displacement pump, which employs a
reciprocating plunger, the pump speed is usually expressed in
reciprocations per minute or revolutions per minute ("rpm"). For a
positive-displacement pump, the pump speed is the product of the
number of plunger strokes per unit time (e.g., rpm) and the plunger
stroke length. Thus, the volumetric flow rate through one of the
pumping chambers of a fluid end of a positive-displacement pump is
directly proportional to the product of the pump speed and the
cross-sectional area of the reciprocating plunger. (Of course, the
fluid end of a pump typically has a plurality of similarly-sized
pumping chambers.)
[0152] As used herein, "average bulk fluid velocity" of a fluid is
determined by the volume of the fluid pumped through a pumping
chamber of a pump over the course of delivering a treatment fluid
that is made up with that fluid into a wellbore divided by the
cross-sectional area of the plunger for the pumping chamber. Of
course, there are numerous geometric factors that affect the local
fluid velocities at various instantaneous times during the pumping
cycle, at various specific locations within a pump, and over the
time of introducing the treatment fluid into a wellbore. In
general, however, it is believed that the multitudinous local fluid
velocities at various instantaneous times and at various specific
locations within a pump throughout the time of introducing the
treatment fluid into a wellbore will generally be lower in
proportion to a lower average bulk fluid velocity through a pumping
chamber of the pump. It is believed that the local fluid velocity
at an instantaneous time during the pumping cycle and at a specific
surface location within the pumping chamber is directly
proportional to the pump speed and plunger size, among other
things.
[0153] Particle erosion occurs when fluid-entrained particles
impinge on surfaces, such as when passing through an orifice,
impinging on a metering surface, or making a sharp angle turn in a
tubing. Places that can be of particular concern for erosion
include, for example, pumps, fluid conveying tubing, surface lines,
chokes, manifolds, work strings, valves, and various downhole
assemblies. All else being equal, such as the type of particles,
the shape and size of the particles, and the concentration of the
particles, a fluid containing a particulate that is moving at a
lower velocity adjacent a particular surface is believed to cause
less erosion to the surface than a fluid moving at higher
velocity.
[0154] It is presently believed that there is a non-direct
relationship of erosive wear to local fluid velocity of a fluid
having a suspended particulate therein. Although the relationship
has not yet been experimentally determined, it is presently
believed that this relationship is exponential. Thus, all else
being equal, e.g., for a given fluid and pump size, the rate of
erosion in a pump is expected to be exponentially related to pump
speed. Table 5 provides an example of such a hypothetical
exponential relationship to are arbitrarily selected base pump
speed, where it is assumed that all else is equal, such as the
type, the shape, mesh size, and concentration of the suspended
particles in a given fluid acting on a given configuration and type
of test coupon.
TABLE-US-00005 TABLE 5 Hypothetical Exponential Relationship of
Erosive Wear to Pump Speed % of a base Multiple of a pump speed
base erosion rate 400% 16 300% 9 200% 4 150% 2.25 Base pump 1.0
speed 70% 0.5 57% 0.33 50% 0.25 33% 0.11
[0155] In contrast, however, it is presently believed that there is
a direct (i.e., non-exponential) relationship of erosive wear to
the concentration of the particulate. Although the relationship has
not yet been experimentally determined, Table 6 provides an example
of such a hypothetical direct relationship of erosion rate to
proppant concentration, assuming a direct proportionality of
one-to-one, where it is assumed that all else would be equal, such
as for a given type and mesh size of proppant in a given fluid at a
given pump speed (directly corresponding to local and average fluid
velocities) acting on a given configuration and type of test
coupon.
TABLE-US-00006 TABLE 6 Hypothetical direct relationship of erosion
rate to proppant concentration % of a base Multiple of
concentration a base of proppant erosion rate 400% 4 300% 3 200% 2
150% 1.5 Base 1.0 concentration 70% 0.7 57% 0.57 50% 0.5 33%
0.33
[0156] It is believed that the difference between a non-direct
(i.e., exponential) relationship between of erosive rate to pump
speed and a direct relationship of erosive rate to concentration of
a suspended particulate can be used as leverage to reduce erosion
in pumping equipment. Thus, it is believed that, when a relatively
high-concentration of the particles of a particle-containing fluid
is separately pumped at a lower pump speed than a relatively-low
concentration of the particles in a different fluid separately
pumped at a higher pump speed, it is overall less damaging to all
the pumps than if the treatment fluid is first mixed and then
pumped downhole. When a treatment fluid is formed and pumped in
such a manner, the damage caused from erosion will be reduced in
all pumps for the different partitioned fluid streams that will
make up the combined treatment fluid directed downhole. Because the
pumps wear less, they require less maintenance and deliver
increased utilization.
[0157] However, this direct relationship of Table 6 between erosion
rate and proppant concentration is believed to hold for only a
central portion of a response curve. It is believed that at very
high concentrations of proppant (in relation to the ranges of
concentrations of proppant typically used in a treatment fluid for
water fracturing), that the response would not hold. Especially in
regard to the range of high concentrations of proppant, it is
believed that particle-to-particle interactions begin to play an
increasing role with increasing concentration. This may provide
additional and unexpected advantage in pumping the first fluid with
a high concentration of particulate relative to a second fluid with
a low concentration of particulate or no particulate.
[0158] The final treatment fluid properties, pump rates, and pump
pressures are set by the reservoir properties and the fluid system
selected for a given treatment schedule. With this information, the
control system optimizes each fluid stream to minimize wear caused
from the pumping of the various partitioned streams used to create
the final treatment fluid for the stimulation of the well and to
allow for optimal use of produced water. It should be understood
that the control system would be based on computer computations and
preferably several parameters of the method would be under computer
control.
[0159] Preferably the first fluid and the second fluid each
comprise at least 10% by weight of the treatment fluid. According
to a more-preferred embodiment, the second fluid comprises at least
50% by weight of the treatment fluid.
[0160] According to a preferred embodiment of the method, the first
fluid is a water-based fluid, and the second fluid is a water-based
fluid. According to a preferred embodiment, the first fluid
comprises at least 10% by weight of the treatment fluid, and the
second fluid comprises at least 10% by weight of the treatment
fluid According to a more-preferred embodiment, the first fluid
comprises at least 25% by weight of the treatment fluid, and the
second fluid comprises at least 25% by weight of the treatment
fluid.
[0161] Preferably, the method further comprises the step of:
controlling the first concentration of the particulate in the first
fluid, the second concentration of the particulate in the second
fluid, the volumetric flow rate and pump speed of the first fluid,
and the volumetric flow rate and pump speed of the second fluid to
reduce the overall wear rate on the first and second pumps.
[0162] It should be understood that there are several ways to
control the average bulk fluid velocity through a pumping chamber
of a pump and for pumping a fluid to achieve a desired total
volumetric flow rate, including varying any one or more of the
following: (a) the pump speed; (b) using more pumping chambers
(e.g., pumps having more pumping chambers or using more pumps); or
(c) using pumps having larger pumping chambers (e.g., larger
diameter plungers). For example, simply using two pumps of the same
type in place of one, each operated at reduced speed, would allow
for maintaining volumetric fluid flow rate and reducing erosion
through the pumps. Another example would be to selectively use the
available pumps that have the largest fluid ends (i.e., the largest
pumping chambers with the largest diameter plungers) for the first
fluid containing the relatively high concentration of particulate
and using other pumps having smaller fluid ends (i.e., smaller
pumping chambers with smaller diameter plungers) for the second
fluid containing the relatively low concentration of particulate or
no particulate. Of course, any combination of these embodiments can
be used to advantageously reduce the average bulk fluid velocity of
the first fluid.
[0163] It should also be understood that the "average bulk fluid
velocity" may refer to the average bulk fluid velocity over a
plurality of pumping chambers that may be used in pumping the same
type of fluid, including through different sizes of pumps operated
at different pump speeds. Further, it should be understood that the
average bulk fluid velocity refers to the average bulk fluid
velocity for a fluid over the course of pumping the treatment fluid
downhole. It should also be understood that the first and second
pumps may be part of an array comprising more than two pumps. If an
array of pumps is involved, in such a case the average bulk fluid
velocity of the first fluid being pumped through first pump means
the average of the bulk fluid velocities through the plurality of
pumping chambers of the pumps used to pump the first fluid. The
average bulk fluid velocity of the pumping of the second fluid
would be determined similarly.
[0164] As previously mentioned, it should be understood that the
second concentration of the particulate may be zero. For example,
according to a preferred embodiment, (i) the first concentration of
the particulate in the first fluid is greater than 200% of the
merged concentration of the particulate; and (ii) the first fluid
is pumped at an average bulk fluid velocity that is less than 70%
of the average bulk fluid velocity at which the second fluid is
pumped. As a hypothetical example according to this embodiment, a
ratio of 3 pumps to 2 pumps (assuming identical types and sizes of
pumps) could be operated as follows: Three of the pumps would
operate at about 70% pump speed to pump a first fluid having 200%
of the concentration of proppant desired for the final treatment
fluid. Two of the pumps would operate at 100% pump speed to pump a
second fluid without having any proppant therein. (It should be
understood, of course, that "100% pump speed" may be well under the
maximum operating capacity of a pump in order to prevent
overloading of the transmission between the engine and the fluid
end of the pump.) After pumping, the first and second fluid would
be merged through a manifold or multiple manifolds and directed
into a wellbore. The first fluid would account for 50% by volume of
the treatment fluid. The second fluid would account for about 50%
by volume of the treatment fluid. The resulting treatment fluid
would have the desired concentration of proppant.
[0165] As another hypothetical example according to this
embodiment, a ratio of 2 pumps to 2 pumps (assuming identical types
and sizes of pumps) could be operated as follows: Two of the pumps
could operate at about 50% pump speed to pump a first fluid having
200% of the concentration of proppant desired for the treatment
fluid. Two of the pumps would operate at 100% pump speed to pump a
second fluid having only 50% of the concentration of proppant
desired for the treatment fluid. After pumping, the first and
second fluid would be merged through a manifold or multiple
manifolds and directed into a wellbore. The first fluid would
account for about 2/3 by volume of the treatment fluid. The second
fluid would account for about 1/3 by volume of the treatment fluid.
The resulting treatment fluid would have the desired concentration
of proppant.
[0166] According to a presently more preferred embodiment, (i) the
first concentration of the particulate in the first fluid is
greater than 400% the merged concentration of the particulate; and
(ii) the first fluid is pumped at an average bulk fluid velocity
that is less than 50% of the average bulk fluid velocity at which
the second fluid is pumped. As a hypothetical example according to
this embodiment, a ratio of 2 pumps to 3 pumps (assuming identical
types and sizes of pumps) could be operated as follows: Two of the
pumps would operate at 50% pump speed to pump a first fluid having
400% of the concentration of proppant desired for the final
treatment fluid. Three of the pumps would operate at 100% pump
speed to pump a second fluid without any proppant therein. After
pumping, the first and second fluid would be merged through a
manifold or multiple manifolds and directed into a wellbore. The
first fluid would account for 25% by volume of the final treatment
fluid. The second fluid would account for 75% by volume of the
final treatment fluid. The resulting treatment fluid would have the
desired concentration of proppant.
[0167] FIG. 1 is a flow diagram of a conventional equipment spread
used in hydraulic fracturing of a well. A typical fracturing uses
water that is entirely made up of potable water, freshwater, and/or
treated water. The water is mixed with a viscosity-increasing agent
in an "ADP OR GEL PRO" mixer or mixing step to provide a higher
viscosity fluid to help suspend sand or other particulate. The
water and/or the higher-viscosity water-based fluid are then mixed
with sand in a blender to form a treatment fluid for fracturing the
well. An array of high-pressure ("HP") pumps that are arranged in
parallel is used to deliver the treatment fluid into the wellbore
of a well.
[0168] FIG. 2 is a flow diagram of an example of the equipment
spread that may be used in various methods according to the
inventions. Fluid stream 1 is comprised of, for example, potable
water, freshwater, treated water, or any combination thereof, such
that it has, for example, relatively low total dissolved solids.
The treated water for use in Fluid stream 1 may have been subjected
to water treatments such as filtration to remove undissolved
solids, removal of certain dissolved ions, pH adjustment, and
bacterial treatment. Fluid stream 2 is comprised of, for example,
untreated produced, returned water, brine, or any combination
thereof such that it has, for example, relatively high total
dissolved solids. A low pressure pump, e.g., a centrifugal pump,
may be used to transport the water for fluid stream 2 to the HP
pumps. The relatively clean water is mixed with a
viscosity-increasing agent to provide a higher viscosity fluid to
help suspend sand or other particulate. The relatively clean water
and/or the higher-viscosity fluid are then mixed with sand in a
blender. An array of HP pumps that are arranged in parallel is used
to pump fluid stream 1 and fluid stream 2, after which the fluid
streams are merged to form a treatment fluid and directed into the
wellbore of a well. Chemicals, such as viscosity-increasing agent
or fluid friction-reducing agent, and other materials, such as
sand, may be partitioned via a partitioning manifold between the
fluid stream 1 and fluid stream 2. According to one of the aspects
of the inventions, the pumps may be operated to pump fluid stream 1
and fluid stream 2 at different rates based on different
concentrations of particulate in the fluid streams to reduce pump
wear and maintenance.
[0169] FIG. 3 is a flow diagram similar to the flow diagram of FIG.
2 with the addition of an optional step of water-treatment
operations in fluid stream 2. The water-treatment operations may
be, for example, for the removal of undesirable components. Water
treatments may include filtration to remove undissolved solids,
removal of certain dissolved ions, pH adjustment, and bacterial
treatment. The water treatments used to obtain treated water for
use in fluid stream 1 are expected to be different than those used
in fluid stream 2.
[0170] Furthermore, the split stream process gives the ability to
use lower-quality water, such as untreated produced water, in more
types of well treatments where the TDS of the produced water (or
specific ions) would interfere with the chemical reactions required
for the treatment. This is accomplished by mixing the chemicals and
proppant in concentrated form through one or more blenders and
pre-blenders using higher-quality water, such as freshwater,
potable water, or treated water. The rest of the required water for
the final treatment fluid can be of the lower-quality water, such
as untreated formation water, produced water, or flow back waters.
This process allows the addition of different viscosity-increasing
agents, friction-reducing agents, and other fluid-property
modifying agents in any of the fluid streams depending on the
compatibility with the type of water. Preferably, for example, the
unhydrated hydratable polymer would be used with the higher-quality
water, for example, to help suspend the proppant.
[0171] There is also a commercial advantage through increasing the
number of stimulation treatments that can be pumped using
lower-quality water, such as untreated produced water. This reduces
the amount of higher-quality water, such as freshwater or potable
water, that must be purchased and also the cost paid to dispose of
the produced water that is normally unacceptable for use in making
up a well treatment fluid due to chemical compatibility issues.
[0172] The invention also has the ability to use varying amounts of
higher-quality water vs. lower-quality water in the same well
treatment and to mix and blend modifying chemical agents with the
most compatible water type. This methodology, thus, gives the
chemical agents time to react with the other components before
combining with the other fluid streams.
[0173] In an example, the total required treating volume would be
1/3 relatively clean water (i.e., potable water, freshwater, or
partially-treated water) with proppant and 2/3 untreated water
(i.e., brackish water to brine or produced water). These two
streams can be combined to create the final treatment fluid after
passing through the pumping equipment to yield a treatment fluid
having the desired properties.
Pumping Streams with Different Concentrations of Particulate and
Hydratable Additive
[0174] The fifth aspect of the inventions generally relates to
pumping a first fluid having a relatively high concentration of a
particulate suspended therein and pumping a second fluid having
either none of the particulate or a relatively low concentration of
the particulate suspended therein, and then merging at least the
first and second fluids to form a treatment fluid having a merged
concentration of the particulate. According to this aspect, the
first fluid also has a relatively high concentration of a
hydratable additive and the second fluid has either none or a
relatively low concentration of the additive. In this context, the
particulate means and refers to a solid, insoluble material having
consistently defined characteristics, such as mesh size. An example
of a particulate includes, for example, 20-40 mesh sand for use as
proppant. The additive is preferably selected from the group
consisting of a water-soluble viscosity-increasing agent, a
water-soluble a friction-reducing agent, or a water-soluble
elasticity-increasing agent.
[0175] According to this fifth aspect, the method comprises the
steps of: (a) pumping a first fluid comprising a first aqueous
solution with a first positive-displacement pump; (b) pumping a
second fluid comprising a second aqueous solution with a second
positive-displacement pump; (c) merging at least the first and
second fluids to form a treatment fluid; and (d) directing the
treatment fluid into a wellbore. For this aspect of the inventions:
(i) the treatment fluid comprises a merged concentration of a
particulate and a merged concentration of a hydratable additive;
(ii) the first fluid comprises a first concentration of the
particulate that is substantially higher than the merged
concentration of the particulate and a first concentration of the
additive that is substantially higher than the merged concentration
of the additive; and (iii) the second fluid comprises a second
concentration of the particulate that is substantially lower than
the merged concentration of the particulate and a second
concentration of the additive that is substantially lower than the
merged concentration of the additive.
[0176] It is believed that the combination of both a higher
concentration of the particulate combined with a higher
concentration of the hydratable additive is capable of reducing
overall erosive wear on pumps. According to this aspect, it is
believed that there is a synergistic advantage in reducing the wear
based on the combination of both an unusually higher concentration
of the particulate and an unusually high concentration of the
hydratable additive in the pumping of first fluid. It is believed
this is an independent method capable of reducing overall pump
wear.
[0177] In addition to controlling the relative concentrations of
the particulate and the hydratable additive, it can also be
desirable that the first fluid is pumped at a substantially lower
pump speed than the pump speed at which the second fluid is
pumped.
[0178] Preferably, the first aqueous solution and the second
aqueous solution each comprise at least 10% by weight of the
treatment fluid. More preferably, the second aqueous solution
comprises at least 50% by weight of the treatment fluid. According
to a preferred embodiment, the first fluid is a water-based fluid
and the second fluid is a water-based fluid. According to a more
preferred embodiment, the first aqueous solution comprises at least
25% by weight of the treatment fluid and the second aqueous
solution comprises at least 25% by weight of the treatment
fluid.
[0179] According to another preferred embodiment of the fifth
aspect of the inventions, the step of pumping a first fluid further
comprises pumping the first fluid with a first pump, and wherein
the step of pumping a second fluid further comprises pumping the
second fluid with a second pump. Preferably, the method further
rises the step of: controlling the first concentration of the
particulate in the first fluid, the first concentration of the
hydratable additive in the first fluid, the second concentration of
particulate in the second fluid, and the second concentration of
the additive in the second fluid to reduce the overall wear rate on
the first and second pumps. It should be understood that the first
and second pumps may be positive displacement pumps. It should also
be understood that the first and second pumps may be part of an
array comprising more than two pumps.
[0180] More particularly, it should be understood that the second
concentration of the particulate may be zero. Similarly, it should
be understood that the second concentration of the hydratable
additive may be zero.
[0181] According to a presently preferred embodiment, (i) the first
concentration of the particulate in the first fluid is greater than
200% of the merged concentration of the particulate; and (ii) the
first concentration of the hydratable additive is greater than 200%
of the merged concentration of the additive. According to a
presently more preferred embodiment, (i) the first concentration of
the particulate in the first fluid is greater than 400% the merged
concentration of the particulate; and (ii) the first concentration
of the additive is greater than 400% of the merged concentration of
the additive.
[0182] In addition, it is expected that it will be synergistically
advantageous to combine this aspect of the inventions with
controlling the pumping rate of the fluids. Preferably, for
example, the first fluid is pumped at a substantially lower pump
speed than the pump speed at which second fluid is pumped.
Various Combination of Steps
[0183] It should be appreciated that the various steps according to
the inventions can be combined advantageously or practiced together
in various combinations to increase the efficiency and benefits
that can be obtained from the inventions. For example, produced
water could be treated to reduce the concentration of at least one
type of dissolved ions therein. The treated water could be used in
a step of prehydrating an unhydrated hydratable additive. Proppant
could be mixed during or after the step of prehydrating, for
example, wherein the hydratable additive is a viscosity-increasing
agent. In addition, a step of mixing other additives to the fluid
could also be included. The fluid having the treated water and/or
the prehydrated additive could be pumped as a separate stream from
a stream of fluid including the produced water. After pumping, the
two streams could be merged and directed into the wellbore to form
the desired treatment fluid. It should also be understood that more
than two streams of fluid could be formed and merged after pumping
to form the final treatment fluid.
[0184] Thus, the present inventions are well adapted to carry out
the objects and attain the ends and advantages mentioned above as
well as those inherent therein. While preferred embodiments of the
inventions have been described for the purpose of this disclosure,
changes in the sequence of steps and the performance of steps can
be made by those skilled in the art, which changes are encompassed
within the spirit of this invention as defined by the appended
claims.
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